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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2016
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission File Number 1-16417
NUSTAR ENERGY L.P.
(Exact name of registrant as specified in its charter)
Delaware
(State or other jurisdiction of
incorporation or organization)
19003 IH-10 West
San Antonio, Texas
(Address of principal executive offices)
74-2956831
(I.R.S. Employer
Identification No.)
78257
(Zip Code)
Registrant’s telephone number, including area code (210) 918-2000
Securities registered pursuant to Section 12(b) of the Act: Common units representing limited partner interests listed on the New
York Stock Exchange. 8.50% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units representing
limited partner interests listed on the New York Stock Exchange.
Securities registered pursuant to 12(g) of the Act: None.
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes [X] No [ ]
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yes [ ] No [X]
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such
reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every
Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during
the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not
contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller
reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule
12b-2 of the Exchange Act:
Large accelerated filer
[X]
Accelerated filer [ ]
Non-accelerated filer
[ ] (Do not check if a smaller reporting company) Smaller reporting company
[ ]
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes [ ] No [X]
The aggregate market value of the common units held by non-affiliates was approximately $3,207 million based on the last sales
price quoted as of June 30, 2016, the last business day of the registrant’s most recently completed second quarter.
The number of common units outstanding as of January 31, 2017 was 78,650,995.
Table of Contents
NUSTAR ENERGY L.P.
FORM 10-K
TABLE OF CONTENTS
PART I
Items 1., 1A. & 2. Business, Risk Factors and Properties
Overview
Recent Developments
Organizational Structure
Segments
Employees
Rate Regulation
Environmental, Health, Safety and Security
Risk Factors
Properties
Unresolved Staff Comments
Legal Proceedings
Mine Safety Disclosures
Market for Registrant’s Common Units, Related Unitholder Matters and Issuer Purchases of
Equity Securities
PART II
Selected Financial Data
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 1B.
Item 3.
Item 4.
Item 5.
Item 6.
Item 7.
Item 7A.
Quantitative and Qualitative Disclosures about Market Risk
Item 8.
Item 9.
Item 9A.
Item 9B.
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
Item 15.
Item 16.
Signatures
Financial Statements and Supplementary Data
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Controls and Procedures
Other Information
Directors, Executive Officers and Corporate Governance
PART III
Executive Compensation
Security Ownership of Certain Beneficial Owners and Management and Related Unitholder
Matters
Certain Relationships and Related Transactions and Director Independence
Principal Accountant Fees and Services
PART IV
Exhibits and Financial Statement Schedules
Form 10-K Summary
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PART I
Unless otherwise indicated, the terms “NuStar Energy L.P.,” “the Partnership,” “we,” “our” and “us” are used in this report to
refer to NuStar Energy L.P., to one or more of our consolidated subsidiaries or to all of them taken as a whole.
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
In this Form 10-K, we make certain forward-looking statements, including statements regarding our plans, strategies,
objectives, expectations, estimates, predictions, projections, assumptions, intentions and resources. While these forward-
looking statements, and any assumptions upon which they are based, are made in good faith and reflect our current judgment
regarding the direction of our business, actual results will almost always vary, sometimes materially, from any estimates,
predictions, projections, assumptions or other future performance suggested in this report. These forward-looking statements
can generally be identified by the words “anticipates,” “believes,” “expects,” “plans,” “intends,” “estimates,” “forecasts,”
“budgets,” “projects,” “will,” “could,” “should,” “may” and similar expressions. These statements reflect our current views
with regard to future events and are subject to various risks, uncertainties and assumptions. Please read Item 1A. “Risk
Factors” for a discussion of certain of those risks, uncertainties and assumptions.
If one or more of these risks or uncertainties materialize, or if the underlying assumptions prove incorrect, our actual results
may vary materially from those described in any forward-looking statement. Other unknown or unpredictable factors could
also have material adverse effects on our future results. Readers are cautioned not to place undue reliance on this forward-
looking information, which is as of the date of this Form 10-K. We do not intend to update these statements unless we are
required by the securities laws to do so, and we undertake no obligation to publicly release the result of any revisions to any
such forward-looking statements that may be made to reflect events or circumstances after the date of this report or to reflect
the occurrence of unanticipated events.
ITEM 1., 1A. and 2.
BUSINESS, RISK FACTORS AND PROPERTIES
OVERVIEW
NuStar Energy L.P. (NuStar Energy), a Delaware limited partnership, was formed in 1999 and completed its initial public
offering of common units on April 16, 2001. Our common units are traded on the New York Stock Exchange (NYSE) under the
symbol “NS,” and our 8.50% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units trade on the
NYSE under the symbol “NSprA.” Our principal executive offices are located at 19003 IH-10 West, San Antonio, Texas 78257
and our telephone number is (210) 918-2000.
We are engaged in the transportation of petroleum products and anhydrous ammonia, the terminalling and storage of petroleum
products and the marketing of petroleum products. The term “throughput” as used in this document generally refers to barrels
of crude oil or refined product or tons of ammonia, as applicable, that pass through our pipelines, terminals or storage tanks.
We divide our operations into the following three reportable business segments: pipeline, storage and fuels marketing. As of
December 31, 2016, our assets included approximately 8,700 miles of pipeline and 79 terminal and storage facilities that
provide approximately 95 million barrels of storage capacity. The following table summarizes operating income for each of our
business segments:
Pipeline
Storage
Fuels marketing
Year Ended December 31,
2016
2015
(Thousands of Dollars)
$
$
$
248,238
214,801
3,406
$
$
$
270,349
217,818
13,507
We conduct our operations through our wholly owned subsidiaries, primarily NuStar Logistics, L.P. (NuStar Logistics) and
NuStar Pipeline Operating Partnership L.P. (NuPOP). Our revenues include:
•
•
•
tariffs for transporting crude oil, refined products and anhydrous ammonia through our pipelines;
fees for the use of our terminal and storage facilities and related ancillary services; and
sales of crude oil and refined petroleum products.
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We strive to increase unitholder value by:
•
•
•
•
enhancing our existing assets through strategic internal growth projects that expand our business with current and
new customers;
pursuing strategic expansion projects by constructing new assets;
improving our operations, including safety and environmental stewardship, cost control and asset reliability; and
identifying acquisition targets that meet our financial and strategic criteria.
Our internet website address is http://www.nustarenergy.com. Information contained on our website is not part of this report.
Our annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K filed with (or furnished to)
the Securities and Exchange Commission (SEC) are available on our website, free of charge, as soon as reasonably practicable
after we file or furnish such material (select the “Investors” link, then the “SEC Filings” link). We also post our corporate
governance guidelines, code of business conduct and ethics, code of ethics for senior financial officers and the charters of our
board’s committees on our website free of charge (select the “Investors” link, then the “Corporate Governance” link).
Our governance documents are available in print to any unitholder that makes a written request to Corporate Secretary, NuStar
Energy L.P., 19003 IH-10 West, San Antonio, Texas 78257 or corporatesecretary@nustarenergy.com.
RECENT DEVELOPMENTS
Martin Terminal Acquisition. On December 21, 2016, we acquired crude oil and refined product storage assets in Corpus
Christi, TX for $95.7 million, including $2.1 million of capital expenditure reimbursements, from Martin Operating Partnership
L.P. The assets acquired are in our storage segment and include 900,000 barrels of crude oil storage capacity, 250,000 barrels of
refined product storage capacity and exclusive use of the Port of Corpus Christi’s new crude oil dock.
Please refer to Note 4 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary
Data” for further discussion of our acquisitions.
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ORGANIZATIONAL STRUCTURE
Our operations are managed by NuStar GP, LLC, the general partner of our general partner. NuStar GP, LLC, a Delaware
limited liability company, is a consolidated subsidiary of NuStar GP Holdings, LLC (NuStar GP Holdings) (NYSE: NSH).
The following chart depicts a summary of our organizational structure at December 31, 2016.
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Detailed financial information about our segments is included in Note 26 of the Notes to Consolidated Financial Statements in
Item 8. “Financial Statements and Supplementary Data.” The following map depicts our assets at December 31, 2016.
SEGMENTS
PIPELINE
Our pipeline operations consist of the transportation of refined petroleum products, crude oil and anhydrous ammonia. As of
December 31, 2016, we owned and operated:
•
•
•
•
refined product pipelines with an aggregate length of 3,140 miles and crude oil pipelines with an aggregate length
of 1,230 miles in Texas, Oklahoma, Kansas, Colorado and New Mexico (collectively, the Central West System);
a 1,920-mile refined product pipeline originating in southern Kansas and terminating at Jamestown, North
Dakota, with a western extension to North Platte, Nebraska and an eastern extension into Iowa (the East Pipeline);
a 450-mile refined product pipeline originating at Tesoro Corporation’s (Tesoro) Mandan, North Dakota refinery
and terminating in Minneapolis, Minnesota (the North Pipeline); and
a 2,000-mile anhydrous ammonia pipeline originating at the Louisiana delta area that travels north through the
Midwestern United States forking east and west to terminate in Nebraska and Indiana (the Ammonia Pipeline).
We charge tariffs on a per barrel basis for transporting refined products, crude oil and other feedstocks in our refined product
and crude oil pipelines and on a per ton basis for transporting anhydrous ammonia in the Ammonia Pipeline.
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The following table lists information about our pipeline assets as of December 31, 2016:
Region / Pipeline System
Central West System:
McKee System
Three Rivers System
Other
Central West Refined Products Pipelines
South Texas Crude System
Other
Eagle Ford System
McKee System
Ardmore System
Central West Crude Oil Pipelines
Total Central West System
Central East System:
East Pipeline
North Pipeline
Ammonia Pipeline
Total Central East System
Throughput
For the year ended December 31,
Length
(Miles)
Tank Capacity
2016
2015
(Barrels)
(Barrels/Day)
2,276
373
491
3,140
319
194
513
598
119
1,230
4,370
1,920
450
2,000
4,370
—
—
—
—
2,157,000
—
2,157,000
1,039,000
824,000
4,020,000
4,020,000
5,228,000
1,437,000
—
6,665,000
178,373
79,502
57,039
314,914
124,363
59,087
183,450
147,956
60,775
392,181
707,095
143,446
48,343
29,243
221,032
172,590
74,361
60,410
307,361
179,734
85,495
265,229
144,077
62,326
471,632
778,993
132,005
46,951
35,829
214,785
Total
8,740
10,685,000
928,127
993,778
Description of Pipelines
Central West System. The Central West System covers a total of 4,370 miles, including refined product and crude oil pipelines.
The refined product pipelines have an aggregate length of 3,140 miles (Central West Refined Products Pipelines) and transport
gasoline, distillates (including diesel and jet fuel), natural gas liquids and other products produced at the refineries to which
they are connected, including Valero Energy Corporation’s (Valero Energy) McKee and Three Rivers refineries. The crude oil
pipelines have an aggregate length of 1,230 miles (Central West Crude Oil Pipelines). Our crude oil pipelines transport crude
oil and other feedstocks to the refineries to which they are connected, including Valero Energy’s McKee, Three Rivers and
Ardmore refineries, or from the Eagle Ford Shale region to our North Beach marine terminal and to our customers’ refineries in
Corpus Christi, Texas.
Central East System. The Central East System covers a total of 4,370 miles and consists of the East Pipeline, North Pipeline
and Ammonia Pipeline.
The East Pipeline covers 1,920 miles and moves refined products and natural gas liquids north in pipelines ranging in diameter
from 6 inches to 16 inches to NuStar Energy and third party terminals along the system and to receiving pipeline connections in
Kansas. Shippers on the East Pipeline obtain refined petroleum products from refineries in Kansas, Oklahoma and Texas. The
East Pipeline system includes 17 terminals, discussed below, with storage capacity of approximately 3.8 million barrels and
two tank farms with storage capacity of approximately 1.4 million barrels at McPherson and El Dorado, Kansas.
The North Pipeline originates at Tesoro’s Mandan, North Dakota refinery and runs from west to east for approximately 450
miles to its termination in the Minneapolis, Minnesota area. The North Pipeline system includes four terminals, discussed
below, with storage capacity of approximately 1.4 million barrels.
The East and North Pipelines include 21 truck-loading terminals through which refined petroleum products are delivered to
storage tanks and then loaded into petroleum product transport trucks. Revenues earned at these terminals predominately relate
to the volumes transported on the pipeline through fees included in the pipeline tariff. As a result, these terminals are included
in this segment instead of the storage segment.
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The 2,000-mile Ammonia Pipeline originates in the Louisiana delta area, where it connects to three third-party marine terminals
and three anhydrous ammonia plants on the Mississippi River. The line runs north through Louisiana and Arkansas into
Missouri, where at Hermann, Missouri it splits and one branch goes east into Illinois and Indiana, while the other branch
continues north into Iowa and then turns west into Nebraska. The Ammonia Pipeline is connected to multiple third-party-owned
terminals, which include industrial facility delivery locations. Product is supplied to the pipeline from anhydrous ammonia
plants in Louisiana and imported product delivered through the marine terminals. Anhydrous ammonia is primarily used as
agricultural fertilizer. It is also used as a feedstock to produce other nitrogen derivative fertilizers and explosives.
Pipeline Operations
Revenues for the pipelines are based upon origin-to-destination throughput volumes traveling through our pipelines and their
related tariff rates.
In general, shippers on our crude oil and refined product pipelines deliver petroleum products to our pipelines for transport to/
from: (i) refineries that connect to our pipelines, (ii) third-party pipelines or terminals and (iii) NuStar Energy terminals for
further delivery to marine vessels or pipelines. We charge our shippers tariff rates based on transportation from the origination
point on the pipeline to the point of delivery.
Our pipelines are subject to federal regulation by one or more of the following governmental agencies: the Federal Energy
Regulatory Commission (the FERC), the Surface Transportation Board (the STB), the Department of Transportation (DOT),
the Environmental Protection Agency (EPA) and the Department of Homeland Security. Additionally, our pipelines are subject
to the respective state jurisdictions. See “Rate Regulation” and “Environmental, Health, Safety and Security Regulation” below.
The majority of our pipelines are common carrier. Common carrier activities are those for which transportation through our
pipelines is available to any shipper who requests such services and satisfies the conditions and specifications for
transportation. Published tariffs are (i) filed with the FERC for interstate petroleum product shipments, (ii) filed with the
relevant state authority for intrastate petroleum product shipments or (iii) regulated by the STB for our Ammonia Pipeline.
We operate our pipelines remotely through a computerized Supervisory Control and Data Acquisition system.
Demand for and Sources of Refined Products and Crude Oil
Throughputs on our Central West Refined Product Pipelines and the East and North Pipelines depend on the level of demand
for refined products in the markets served by the pipelines and the ability and willingness of the refiners and marketers having
access to the pipelines to supply that demand through our pipelines.
The majority of the refined products delivered through the Central West Refined Product Pipelines and the North Pipeline are
gasoline and diesel fuel that originate at refineries connected to our pipelines. Demand for these products fluctuates as prices
for these products fluctuate. Prices fluctuate for a variety of reasons including the overall balance in supply and demand, which
is affected by general economic conditions, among other factors. Prices for gasoline and diesel fuel tend to increase in the warm
weather months when people tend to drive automobiles more often and for longer distances.
Much of the refined products and natural gas liquids delivered through the East Pipeline and a portion of volumes on the North
Pipeline are ultimately used as fuel for railroads, ethanol denaturant or in agricultural operations, including fuel for farm
equipment, irrigation systems, trucks used for transporting crops and crop-drying facilities. Demand for refined products for
agricultural use, and the relative mix of products required, is affected by weather conditions in the markets served by the East
and North Pipelines. The agricultural sector is also affected by government agricultural policies and crop prices. Although
periods of drought suppress agricultural demand for some refined products, particularly those used for fueling farm equipment,
the demand for fuel for irrigation systems often increases during such times. The mix of refined products delivered for
agricultural use varies seasonally, with gasoline demand peaking in early summer, diesel fuel demand peaking in late summer
and propane demand higher in the fall.
Our refined product pipelines are also dependent upon adequate levels of production of refined products by refineries
connected to the pipelines, directly or through connecting pipelines. The refineries are, in turn, dependent upon adequate
supplies of suitable grades of crude oil. Certain of our Central West Refined Products Pipelines are subject to long-term
throughput agreements with Valero Energy. Valero Energy refineries connected directly to our pipelines obtain crude oil from a
variety of foreign and domestic sources. If operations at one of these refineries were discontinued or significantly reduced, it
could have a material adverse effect on our operations, although we would endeavor to minimize the impact by seeking
alternative customers for those pipelines.
The North Pipeline is heavily dependent on Tesoro’s Mandan, North Dakota refinery, which primarily runs North Dakota crude
oil (although it has the ability to process other crude oils). If operations at the Tesoro refinery were interrupted, it could have a
material adverse effect on our operations. The majority of the refined products transported through the East Pipeline are
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produced at three refineries located at McPherson and El Dorado, Kansas and Ponca City, Oklahoma, which are operated by
CHS Inc., HollyFrontier Corporation and Phillips 66, respectively. The East Pipeline also has access to Gulf Coast supplies of
products through third party connecting pipelines that receive products originating on the Gulf Coast.
Other than the Valero Energy refineries and the Tesoro refinery described above, if operations at any one refinery were
discontinued, we believe (assuming unchanged demand for refined products in markets served by the refined product pipelines)
that the effects thereof would be short-term in nature and our business would not be materially adversely affected over the long-
term because such discontinued production could be replaced by other refineries or other sources.
Our crude oil pipelines are dependent on our customers’ continued access to sufficient crude oil and sufficient demand for
refined products for our customers to operate their refineries. The supply of crude oil production (domestic and foreign) could
increase or decrease with the change in crude oil prices. Changes in crude oil prices could also affect the exploration and
production of shale plays, which could impact crude oil pipelines serving those regions, such as our Eagle Ford System.
However, many of our crude oil pipelines, including the McKee System, are the primary source of crude oil for our customers’
refineries. Therefore, these “demand-pull” pipelines are less affected by changes in crude oil prices.
Demand for and Sources of Anhydrous Ammonia
The Ammonia Pipeline is one of two major anhydrous ammonia pipelines in the United States and the only one capable of
receiving products from outside the United States directly into the system and transporting anhydrous ammonia into the
nation’s corn belt.
Throughputs on our Ammonia Pipeline depend on overall nitrogen fertilizer use, the price of natural gas, which is the primary
component of anhydrous ammonia, and the level of demand for direct application of anhydrous ammonia as a fertilizer for crop
production (Direct Application). Demand for Direct Application is dependent on the weather, as Direct Application is not
effective if the ground is too wet or too dry.
Corn producers have fertilizer alternatives to anhydrous ammonia, such as liquid or dry nitrogen fertilizers. Liquid and dry
nitrogen fertilizers are both less sensitive to weather conditions during application but are generally more costly than anhydrous
ammonia. In addition, anhydrous ammonia has the highest nitrogen content of any nitrogen-derivative fertilizer.
Customers
The largest customer of our pipeline segment was Valero Energy, which accounted for approximately 37% of the total segment
revenues for the year ended December 31, 2016. In addition to Valero Energy, our customers include integrated oil companies,
refining companies, farm cooperatives, railroads and others. No other customer accounted for a significant portion of the total
revenues of the pipeline segment for the year ended December 31, 2016.
Competition and Business Considerations
Because pipelines are generally the lowest-cost method for intermediate and long-haul movement of crude oil and refined
petroleum products, our more significant competitors are common carrier and proprietary pipelines owned and operated by
major integrated and large independent oil companies and other companies in the areas where we deliver products. Competition
between common carrier pipelines is based primarily on transportation charges, quality of customer service and proximity to
end users. Trucks may competitively deliver products in some of the areas served by our pipelines; however, trucking costs
render that mode of transportation uncompetitive for longer hauls or larger volumes.
Most of our refined product pipelines and certain of our crude oil pipelines within the Central West System are physically
integrated with and principally serve refineries owned by Valero Energy. As a result, we do not believe that we will face
significant competition for transportation services provided to the Valero Energy refineries we serve.
Certain of our crude oil pipelines serve areas or refineries impacted by domestic shale oil production in the Eagle Ford,
Permian Basin and Granite Wash regions. Our pipelines also face competition from other crude oil pipelines and truck
transportation in these regions. However, that exposure is mitigated through our long-term contracts and minimum volume
commitments with creditworthy customers.
The East and North Pipelines compete with an independent common carrier pipeline system owned by Magellan Midstream
Partners, L.P. (Magellan) that operates approximately 100 miles east of and parallel to the East Pipeline and in close proximity
to the North Pipeline. Certain of the East Pipeline’s and the North Pipeline’s delivery terminals are in direct competition with
Magellan’s terminals. Competition with Magellan is based primarily on transportation charges, quality of customer service and
proximity to end users.
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Competitors of the Ammonia Pipeline include the other major anhydrous ammonia pipeline, owned by Magellan, which
originates in Oklahoma and Texas and terminates in Minnesota. The competing pipeline has the same Direct Application
demand and weather issues as the Ammonia Pipeline but is restricted to domestically produced anhydrous ammonia. Midwest
production facilities, nitrogen fertilizer substitutes and barge and railroad transportation represent other forms of direct
competition to the Ammonia Pipeline under certain market conditions.
STORAGE
Our storage segment consists of facilities that provide storage, handling and other services for petroleum products, crude oil,
specialty chemicals and other liquids. As of December 31, 2016, we owned and operated:
•
40 terminal and storage facilities in the United States and one terminal in Nuevo Laredo, Mexico, with total
storage capacity of 53.2 million barrels;
• A terminal on the island of St. Eustatius with tank capacity of 14.4 million barrels and a transshipment facility;
• A terminal located in Point Tupper, Canada with tank capacity of 7.8 million barrels and a transshipment facility;
and
•
Six terminals located in the United Kingdom and one terminal located in Amsterdam, the Netherlands, with total
storage capacity of approximately 9.5 million barrels.
Description of Major Terminal Facilities
St. Eustatius. We own and operate a 14.4 million barrel petroleum storage and terminalling facility located on the island of St.
Eustatius in the Caribbean, which is located at a point of minimal deviation from major shipping routes. This facility is capable
of handling a wide range of petroleum products, including crude oil and refined products, and it can accommodate heavily
laden ultra large crude carriers, or ULCCs, for loading and discharging crude oil and other petroleum products. A two-berth
jetty, a two-berth monopile with platform and buoy systems, a floating hose station and an offshore single point mooring (SPM)
buoy with loading and unloading capabilities serve the terminal’s customers’ vessels. The fuel oil and petroleum product
facilities have in-tank and in-line blending capabilities, while the crude tanks have tank-to-tank blending capability and in-tank
mixers. In addition to the storage and blending services at St. Eustatius, this facility has the flexibility to utilize certain storage
capacity for both feedstock and refined products to support our atmospheric distillation unit, which is capable of handling up to
25,000 barrels per day of feedstock, ranging from condensates to heavy crude oil. We own and operate all of the berthing
facilities at the St. Eustatius terminal. Separate fees apply for use of the berthing facilities, as well as associated services,
including pilotage, tug assistance, line handling, launch service, emergency response services and other ship services.
We currently have strategic projects at the St. Eustatius terminal to make it more flexible and marketable. These projects
include: (i) replacing the existing SPM with a refurbished SPM and the installation of two subsea pipelines from the SPM,
which will give us the option to load and unload two different products at the SPM and segregate and store various grades of
crude to and from the SPM, (ii) pipeline improvements and (iii) tank upgrades, repairs and rebuilds. Upon completion of these
projects, we will also have the capability to load or unload three crude vessels at a time. We expect these projects to be
completed by the end of 2017.
Refinery Storage Tanks. We own and operate crude oil storage tanks with an aggregate storage capacity of 10.9 million barrels
that are physically integrated with and serve refineries owned by Valero Energy at Corpus Christi and Texas City, TX and
Benicia, CA. Effective January 1, 2017, we lease our refinery storage tanks in exchange for a fixed fee, whereas these were
previously throughput-based tanks.
St. James, Louisiana. Our St. James terminal, which is located on the Mississippi River near St. James, Louisiana, has a total
storage capacity of 9.9 million barrels. The facility is located on almost 900 acres of land, some of which is undeveloped. The
majority of the storage tanks and infrastructure are suited for light crude oil, with certain of the tanks capable of fuel oil or
heated crude oil storage. Additionally, the facility has one barge dock and two ship docks. Our St. James terminal can receive
product from gathering pipelines in the Gulf of Mexico and deliver to connecting pipelines that supply refineries in the Gulf
Coast and Midwest. The St. James terminal also has two unit train rail facilities and a manifest rail facility, which are served by
the Union Pacific Railroad and have a combined capacity of approximately 200,000 barrels per day.
Point Tupper. We own and operate a 7.8 million barrel terminalling and storage facility located at Point Tupper on the Strait of
Canso, near Port Hawkesbury, Nova Scotia. This facility is the deepest independent, ice-free marine terminal on the North
American Atlantic coast, with access to the East Coast, Canada and the Midwestern United States via the St. Lawrence Seaway
and the Great Lakes system. With one of the premier jetty facilities in North America, the Point Tupper facility can
accommodate heavily laden ULCCs for loading and discharging crude oil, petroleum products and petrochemicals. Crude oil
and petroleum product movements at the terminal are fully automated. Separate fees apply for use of the jetty facility, as well
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as associated services, including pilotage, tug assistance, line handling, launch service, emergency response services and other
ship services.
Linden, New Jersey. Our Linden terminal facility has two terminals that provide deep-water terminalling capabilities in the
New York Harbor and primarily stores petroleum products, including gasoline, jet fuel and fuel oils. The two terminals have a
total storage capacity of 4.6 million barrels and can receive and deliver products via ship, barge and pipeline. The terminal
facility includes two docks. On January 2, 2015, we acquired full ownership of one of the terminals located at the Linden
facility that we previously owned 50% through a joint venture.
Amsterdam. Our Amsterdam terminal has a total storage capacity of 3.8 million barrels. This facility is located at the Port of
Amsterdam and primarily stores petroleum products, including gasoline, diesel and fuel oil. This facility has two docks for
vessels and five docks for inland barges.
Corpus Christi North Beach. We own and operate a 3.2 million barrel crude oil storage and terminalling facility located at the
Port of Corpus Christi in Texas. The facility supports our South Texas Crude System and our customer’s Harvest pipeline
system. It also provides our customers with the flexibility to segregate and deliver crude oil and processed condensate. This
facility has four docks, including one private dock, and can load crude oil onto ships simultaneously on all four docks at a
maximum rate of 95,000 barrels per hour. This facility will have exclusive-use access to the Port of Corpus Christi’s new crude
oil dock expected to be completed in 2017. The Corpus Christi North Beach terminal will have the capacity to move on average
between 650,000 and 700,000 barrels per day and can accommodate Aframax-class vessels.
Terminal and Storage Facilities
The following table sets forth information about our terminal and storage facilities as of December 31, 2016:
Facility
Colorado Springs, CO
Denver, CO
Albuquerque, NM
Abernathy, TX
Amarillo, TX
Corpus Christi, TX
Corpus Christi, TX (North Beach)
Edinburg, TX
El Paso, TX (b)
Harlingen, TX
Laredo, TX
San Antonio, TX (c)
Southlake, TX
Nuevo Laredo, Mexico
Central West Terminals
Pittsburg, CA
Rosario, NM
Catoosa, OK
Houston, TX
Asphalt Terminals
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Tank Capacity
(Barrels)
328,000
110,000
251,000
160,000
269,000
483,000
3,244,000
340,000
419,000
286,000
215,000
375,000
569,000
35,000
7,084,000
398,000
166,000
358,000
86,000
1,008,000
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Facility
Jacksonville, FL
St. James, LA
Texas City, TX (c)
Gulf Coast Terminals
Blue Island, IL
Andrews AFB, MD (a)
Baltimore, MD
Piney Point, MD
Linden, NJ (c)
Paulsboro, NJ
Virginia Beach, VA (a)
North East Terminals
Los Angeles, CA
Selby, CA
Stockton, CA
Portland, OR
Tacoma, WA
Vancouver, WA (c)
West Coast Terminals
Corpus Christi, TX
Texas City, TX
Benicia, CA
Refinery Storage Tanks
Grays, England
Eastham, England
Runcorn, England
Grangemouth, Scotland
Glasgow, Scotland
Belfast, Northern Ireland
United Kingdom Terminals
St. Eustatius, the Netherlands
Amsterdam, the Netherlands
Point Tupper, Canada
Tank Capacity
(Barrels)
2,593,000
9,917,000
2,964,000
15,474,000
690,000
75,000
818,000
5,402,000
4,647,000
74,000
41,000
11,747,000
608,000
3,074,000
816,000
1,345,000
391,000
774,000
7,008,000
4,030,000
3,141,000
3,683,000
10,854,000
1,958,000
2,096,000
149,000
719,000
353,000
408,000
5,683,000
14,411,000
3,834,000
7,778,000
Total Terminals and Storage Facilities
84,881,000
(a) Terminal facility also includes pipelines to U.S. government military base locations.
(b) We own a 67% undivided interest in the El Paso refined product terminal. The tank capacity represents the proportionate share of
capacity attributable to our ownership interest.
(c) Location includes two terminal facilities.
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Storage Operations
Revenues for the storage segment include fees for tank storage agreements, where a customer agrees to pay for a certain
amount of storage in a tank over a period of time (storage terminal revenues), and throughput agreements, where a customer
pays a fee per barrel for volumes moving through our terminals (throughput terminal revenues). Our terminals also provide
blending, additive injections, handling and filtering services for which we charge additional fees. We previously charged a fee
for each barrel of crude oil and certain other feedstocks that we deliver to Valero Energy’s Benicia, Corpus Christi West and
Texas City refineries from our crude oil refinery storage tanks. Effective January 1, 2017, we lease these refinery storage tanks
in exchange for a fixed fee. Certain of our facilities charge fees to provide marine services such as pilotage, tug assistance, line
handling, launch service, emergency response services and other ship services.
Demand for Refined Petroleum Products and Crude Oil
The operations of our refined product terminals depend in large part on the level of demand for products stored in our terminals
in the markets served by those assets. The majority of products stored in our terminals are refined petroleum products. Demand
for our terminalling services will generally increase or decrease with demand for refined petroleum products, and demand for
refined petroleum products tends to increase or decrease with the relative strength of the economy. In addition, the forward
pricing curve can have an impact on demand. For example, in a contango market (when the price for future storage is expected
to exceed current prices), demand for storage services will generally increase. As of December 31, 2016, almost all of our tank
storage capacity is under contract.
Crude oil delivered to our St. James terminal through our unit train facilities, and crude oil delivered to our Corpus Christi
North Beach terminal will generally increase or decrease with crude oil production rates in the Bakken and Eagle Ford shale
plays, respectively. In addition, the market price relationship between various grades of crude oil impacts the demand for our
unit train facilities at our St. James terminal, which can affect our profit sharing and volumes.
Customers
We provide storage and terminalling services for crude oil and refined petroleum products to many of the world’s largest
producers of crude oil, integrated oil companies, chemical companies, oil traders and refiners. In addition, our blending
capabilities in our storage assets have attracted customers who have leased capacity primarily for blending purposes. The
largest customer of our storage segment is Valero Energy, which accounted for approximately 21% of the total revenues of the
segment for the year ended December 31, 2016. No other customer accounted for a significant portion of the total revenues of
the storage segment for the year ended December 31, 2016.
Competition and Business Considerations
Many major energy and chemical companies own extensive terminal storage facilities. Although such terminals often have the
same capabilities as terminals owned by independent operators, they generally do not provide terminalling services to third
parties. In many instances, major energy and chemical companies that own storage and terminalling facilities are also
significant customers of independent terminal operators. Such companies typically have strong demand for terminals owned by
independent operators when independent terminals have more cost-effective locations near key transportation links, such as
deep-water ports. Major energy and chemical companies also need independent terminal storage when their owned storage
facilities are inadequate, either because of size constraints, the nature of the stored material or specialized handling
requirements.
Independent terminal owners generally compete on the basis of the location and versatility of terminals, service and price. A
favorably located terminal will have access to various cost-effective transportation modes both to and from the terminal.
Transportation modes typically include waterways, railroads, roadways and pipelines.
Terminal versatility is a function of the operator’s ability to offer complex handling requirements for diverse products. The
services typically provided by the terminal include, among other things, the safe storage of the product at specified temperature,
moisture and other conditions, as well as receipt at and delivery from the terminal, all of which must comply with applicable
environmental regulations. A terminal operator’s ability to obtain attractive pricing is often dependent on the quality, versatility
and reputation of the facilities owned by the operator. Although many products require modest terminal modification, operators
with versatile storage capabilities typically require less modification prior to usage, ultimately making the storage cost to the
customer more attractive.
Our St. Eustatius and Point Tupper terminals have historically functioned as “break bulk” facilities, which handled imports of
light crude from foreign sources into the U.S. to satisfy U.S. East Coast and Gulf Coast refinery demand for light crude. Light
crude suppliers brought the crude from the Middle East and other foreign regions on very large ships, which are efficient for
long routes. These large ships, due to draft constraints, are unable to navigate far enough inland to deliver directly to U.S.
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shores, which necessitates unloading these ships to storage and subsequent loading onto smaller ships that can bring the crude
to the refiners, a process referred to as “break bulk.” Both terminals are well-located to provide this service.
As the supply of light crude from various U.S. shale formations has increased, U.S. demand for foreign light crude oil,
particularly on the U.S. Gulf Coast, has dropped. This reduced demand for imported light crude has, in turn, changed oil trade
flow patterns around the world, thereby depressing the demand for break bulk services. At the same time, South American
production of heavy crude has ramped up significantly. As demand for export of heavy crude out of South America has risen,
so has the demand for “build bulk” services. In order to reduce costs and increase efficiencies for long routes to customers
abroad, exporting producers need to consolidate their heavy oil cargos from the small ships used to move the heavy crude off
shore to a large vessel that is more efficient for long routes, a process referred to as “build bulk.” Our St. Eustatius terminal’s
location is well-suited to build bulk for South American producers headed to customers overseas, primarily in Asia.
We may face increased competition from new and/or expanding terminals near our locations, if those facilities offer either
break bulk or build bulk services, as demanded by the applicable oil trade flows, now and in the future.
Our crude oil refinery storage tanks are physically integrated with and serve refineries owned by Valero Energy. Additionally,
we have entered into various agreements with Valero Energy governing the usage of these tanks. As a result, we believe that we
will not face significant competition for our services provided to those refineries.
FUELS MARKETING
Fuels Marketing Operations
Our fuels marketing operations involve the purchase of crude oil, fuel oil, bunker fuel, fuel oil blending components and other
refined products for resale. These operations provide us the opportunity to generate additional gross margin while
complementing the activities of our storage segment. We utilize storage assets, including our own terminals and rail unloading
facilities, at our St. James, Texas City and St. Eustatius terminals. Rates charged by our storage segment to the fuels marketing
segment are consistent with rates charged to third parties.
Within our fuels marketing operations, we purchase crude oil and refined petroleum products for resale. The results of
operations for the fuels marketing segment depend largely on the margin between our cost and the sales prices of the products
we market. Therefore, the results of operations for this segment are more sensitive to changes in commodity prices compared to
the operations of the pipeline and storage segments.
Since our fuels marketing operations expose us to commodity price risk, we enter into derivative instruments to mitigate the
effect of commodity price fluctuations on our operations. The derivative instruments we use consist primarily of commodity
futures and swap contracts.
Customers
Fuels marketing customers include major integrated refiners and trading companies. Customers for our bunker fuel sales are
mainly ship owners, including cruise line companies. No customer accounted for a significant portion of the total revenues of
the fuels marketing segment for the year ended December 31, 2016.
Competition and Business Considerations
Our fuels marketing operations have numerous competitors, including large integrated refiners, marketing affiliates of other
partnerships in our industry, as well as various international and domestic trading companies. In the sale of bunker fuel, we
compete with ports offering bunker fuels that are along the route of travel of the vessel.
EMPLOYEES
As of December 31, 2016, we had 1,661 employees. We believe that we have a satisfactory relationship with our employees.
RATE REGULATION
Several of our pipelines are interstate common carrier pipelines, which are subject to regulation by the FERC under the
Interstate Commerce Act (ICA) and the Energy Policy Act of 1992 (the EP Act). The ICA and its implementing regulations give
the FERC authority to regulate the rates charged for service on interstate common carrier pipelines and generally require the
rates and practices of interstate liquids pipelines to be just, reasonable, not unduly discriminatory and not unduly preferential.
The ICA also requires tariffs that set forth the rates a common carrier pipeline charges for providing transportation services on
its interstate common carrier liquids pipelines, as well as the rules and regulations governing these services, to be maintained
on file with the FERC and posted publicly. The EP Act deemed certain rates in effect prior to its passage to be just and
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reasonable and limited the circumstances under which a complaint can be made against such “grandfathered” rates. The EP Act
and its implementing regulations also allow interstate common carrier liquids pipelines to annually index their rates up to a
prescribed ceiling level and require that such pipelines index their rates down to the prescribed ceiling level if the index is
negative. In addition, the FERC retains cost-of-service ratemaking, market-based rates and settlement rates as alternatives to
the indexing approach.
The Ammonia Pipeline is subject to regulation by the STB pursuant to the Interstate Commerce Act applicable to such pipelines
(which differs from the ICA applicable to interstate liquids pipelines). Under that regulation, the Ammonia Pipeline’s rates,
classifications, rules and practices related to the interstate transportation of anhydrous ammonia must be reasonable and, in
providing interstate transportation, the Ammonia Pipeline may not subject a person, place, port or type of traffic to
unreasonable discrimination.
In addition to federal regulatory body oversight, various states, including Colorado, Kansas, Louisiana, North Dakota and
Texas, maintain commissions focused on the rates and practices of common carrier pipelines offering services within their
borders. Although the applicable state statutes and regulations vary, they generally require that intrastate pipelines publish
tariffs setting forth all rates, rules and regulations applying to intrastate service, and generally require that pipeline rates and
practices be just, reasonable and nondiscriminatory.
Shippers may challenge tariff rates, rules and regulations on our pipelines. In most instances, state commissions have not
initiated investigations of the rates or practices of pipelines in the absence of shipper complaints. There are no pending
challenges or complaints regarding our tariffs.
ENVIRONMENTAL, HEALTH, SAFETY AND SECURITY REGULATION
Our operations are subject to extensive federal, state and local environmental laws and regulations, in the U.S. and in the other
countries in which we operate, including those relating to the discharge of materials into the environment, waste management,
remediation, the characteristics and composition of fuels and pollution prevention measures, among others. Our operations are
also subject to extensive federal, state and local health and safety laws and regulations, including those relating to worker and
pipeline safety, pipeline integrity and operator qualifications. The principal environmental and safety risks associated with our
operations relate to unauthorized or unpermitted emissions into the air, unauthorized releases into soil, surface water or
groundwater, personal injury and property damage. Compliance with these environmental, health and safety laws, regulations
and related permits increases our capital expenditures and operating expenses, and violation of these laws, regulations or
permits could result in significant civil and criminal liabilities, injunctions or other penalties.
We have adopted policies, practices and procedures to address pollution control, pipeline integrity, operator qualifications,
public relations and education, process safety management, risk management planning, hazard communication, emergency
response planning, community right-to-know, occupational health and the handling, storage, use and disposal of hazardous
materials. Our policies are designed to comply with applicable federal, state and local laws and regulations and to prevent
material environmental or other damage, to ensure the safety of our pipelines, our employees, the public and the environment
and to limit the financial liability that could result from such events. Future governmental action and regulatory initiatives
could necessitate changes to operating permits and procedures, additional remedial actions or increased capital expenditures
and operating costs. While we believe that we are in substantial compliance with the health, safety and environmental
regulations applicable to us, risks of additional costs and liabilities are inherent within the industry, and there can be no
assurances that significant costs and liabilities will not be incurred in the future.
It is possible that these statutes and the related regulations may be revised to be more restrictive in the future, necessitating
additional capital expense to ensure our operations are in compliance. We are unable to estimate the effect on our financial
condition or results of operations or the amount and timing of such required expenditures. In 2016, our capital expenditures
attributable to compliance with environmental regulations were $14.3 million, and we currently project spending to be
approximately $17.7 million in this regard in 2017.
Violations of any of the environmental, health, safety and security statutes and related regulations discussed below could result
in significant costs and liabilities. It is possible that these statutes and the related regulations may be revised to be more
restrictive in the future, necessitating additional capital expense to ensure our operations are in compliance. However, while
compliance may affect our capital expenditures and operating expenses, we believe that the cost of such compliance will not
have a material impact on either our competitive position or our financial condition or results of operations.
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RENEWABLE ENERGY AND ALTERNATIVE FUEL MANDATES
Several federal and state programs require, subsidize or encourage the purchase and use of renewable energy and alternative
fuels, such as battery-powered engines, biodiesel, wind energy and solar energy. These programs may over time offset
projected increases or reduce the demand for refined petroleum products, particularly gasoline, in certain markets. The
increased production and use of biofuels may also create opportunities for additional pipeline transportation and additional
blending opportunities within the storage segment, although that potential cannot be quantified at present. Other legislative
changes may similarly alter the expected demand and supply projections for refined petroleum products in ways that cannot be
predicted.
WATER
The Federal Water Pollution Control Act, as amended, also known as the Clean Water Act, as well as analogous or more
stringent state and local statutes and regulations, impose restrictions and strict controls regarding the discharge of pollutants
into state waters or waters of the United States. The discharge of pollutants into waters is generally prohibited, except in
accordance with the terms of a permit issued by applicable federal or state authorities. The Oil Pollution Act further regulates
the discharge of oil and the response to and liability for oil spills. The Rivers and Harbors Act also regulates pipeline crossings
of waterways.
AIR
Discharges of pollutants into the air are restricted and controlled by the Federal Clean Air Act, as amended, and various
applicable state and local statutes and regulations. These laws and related regulations generally require permits issued by
applicable federal or state authorities for any discharge and also impose various monitoring and reporting requirements. Such
laws and regulations may require a facility to obtain pre-approval for the construction or modification of certain projects or
facilities expected to produce air emissions or result in the increase of existing air emissions, and obtain and strictly comply
with the provisions of any air permits.
SOLID WASTE
The Federal Resource Conservation and Recovery Act (RCRA) and analogous or more stringent state and local statutes and
regulations impose restrictions and strict controls regarding solid wastes, including hazardous wastes. We currently are not
required to comply with a substantial portion of RCRA requirements because we do not operate any waste treatment, storage or
disposal facilities. However, it is possible that additional wastes, which could include wastes currently generated during
operations, will be designated as hazardous wastes. Hazardous wastes are subject to more rigorous and costly disposal
requirements than are non-hazardous wastes.
HAZARDOUS SUBSTANCES
The Federal Comprehensive Environmental Response, Compensation and Liability Act, referred to as CERCLA or
“Superfund,” and analogous or more stringent state and local statutes and regulations, impose restrictions and liability,
including joint and several liability, without regard to fault or the legality of the original act, on some classes of persons that
contributed to the release or threatened release of a hazardous substance into the environment. These classes of persons can
include the owner or operator of the facility and those that disposed or arranged for the disposal of the hazardous substances.
CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats that endanger public health
or the environment and to seek recovery from the responsible classes of persons for the costs they incur. In the course of our
ordinary operations, we may generate and arrange for the disposal of wastes that fall within CERCLA’s definition of a
hazardous substance.
We currently own or lease, and have in the past owned or leased, properties where hazardous substances are being or have been
handled. Although we believe that we have utilized operating and disposal practices that were standard in the industry at the
time, substances may have been disposed of or released on or under the properties owned or leased by us or on or under other
locations where these wastes have been taken for disposal. In addition, we acquired many of these properties from third parties,
and we did not control those third parties’ treatment and disposal or release of hazardous substances. These properties and
substances disposed thereon may be subject to CERCLA, RCRA and analogous state and local statutes and regulations. Under
these laws, we could be required to remove or remediate previously disposed substances (including substances disposed of or
released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform
remedial operations to prevent future contamination. In addition, we may be exposed to joint and several liability under
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CERCLA for all or part of the costs required to clean up sites at which hazardous substances may have been disposed of or
released into the environment.
While remediation of subsurface contamination is in process at several of our facilities, based on currently available
information, we believe that the cost of these activities should not materially affect our financial condition or results of
operations. The aggregate total cost of a given remediation project can be difficult to estimate, and, therefore, there can be no
assurances that the future costs will not become material. Further, it is possible that these statutes and the related regulations
may be revised to be more restrictive in the future, necessitating additional capital expense to ensure compliance. We are unable
to estimate the effect on our financial condition or results of operations or the amount and timing of such required expenditures.
PIPELINE AND OTHER ASSET INTEGRITY AND SAFETY
Our pipeline, storage tank and other operations are subject to extensive federal, state and local statutes and regulations
governing mechanical integrity and safety, including those in Title 49 of the United States Code and its implementing
regulations. These statutes and regulations include requirements for safe operation, maintenance, testing and corrosion control,
and qualification programs for operating personnel. In addition, other requirements can include reviewing and updating existing
pipeline safety public education programs, providing information for the National Pipeline Mapping System, maintaining spill
response plans, conducting spill response training, implementing integrity management programs and managing pipeline
control centers.
SECURITY
We are also subject to Coast Guard and Department of Homeland Security Chemical Facility Anti-Terrorism Standards, which
are designed to regulate the security of high-risk chemical facilities, and to the Transportation Security Administration’s
Pipeline Security Guidelines. We have implemented an inspection program designed to monitor and enforce compliance with
all of these requirements. We believe that we are in material compliance with all applicable laws and regulations regarding the
security of our facilities. While we are not currently subject to governmental standards for the protection of computer-based
systems and technology from cyber threats and attacks, proposals to establish such standards are being considered by the U.S.
Congress and by U.S. Executive Branch departments and agencies, including the Department of Homeland Security, and we
may become subject to such standards in the future. We currently have our own cybersecurity programs and protocols in place;
however, we cannot guarantee their effectiveness, and successful penetration of our critical systems could have a material effect
on our operations and those of our customers.
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RISKS RELATED TO OUR BUSINESS
RISK FACTORS
We may not be able to generate sufficient cash from operations to enable us to pay quarterly distributions to our unitholders
at current levels.
The amount of cash that we can distribute to our unitholders each quarter principally depends upon the amount of cash we
generate from our operations, which fluctuates from quarter to quarter based on, among other things:
throughput volumes transported in our pipelines;
storage contract renewals or throughput volumes in our terminals and storage facilities;
tariff rates and fees we charge and the revenue we realize for our services;
demand for and supply of crude oil, refined products and anhydrous ammonia;
the effect of worldwide energy conservation measures;
our operating costs;
the costs to comply with environmental, health, safety and security laws and regulations;
•
•
•
•
•
•
•
• weather conditions;
•
•
•
domestic and foreign governmental regulations and taxes;
prevailing economic conditions; and
the results of our marketing, trading and hedging activities, which fluctuate depending upon the relationship
between refined product prices and prices of crude oil and other feedstocks.
In addition, the amount of cash that we will have available for distribution depends on other factors, including:
•
•
•
•
•
•
our debt service requirements and restrictions on distributions contained in our current or future debt agreements;
the sources of cash used to fund our acquisitions;
our capital expenditures;
fluctuations in our working capital needs;
issuances of debt and equity securities and ability to access the capital markets; and
adjustments in cash reserves made by our general partner, in its discretion.
It is possible that one or more of the factors listed above may serve to reduce our available cash to such an extent that we could
be rendered unable to pay distributions at the current level or at all in a given quarter. Furthermore, cash distributions to our
unitholders depend primarily upon our cash flows, including cash flows from reserves and working capital borrowings, and not
solely on profitability, which is affected by non-cash items, and we may make cash distributions during periods in which we
record net losses and may not make cash distributions during periods in which we record net income.
Continued low crude oil prices could have an adverse impact on our results of operations, cash flows and ability to make
distributions to our unitholders.
Since late 2015, the price of crude oil has been depressed, which has caused most crude oil producers to reduce their capital
spending and drilling activity and narrow their focus to assets in the most cost-advantaged regions. On the other hand, refiners
have benefited from lower crude prices, to the extent that lower feedstock price has been coupled with higher demand for
certain refined products in some regional markets. While only a relatively small proportion of our total business is directly
affected by the price of crude, a further protracted period of low crude oil prices and overall economic downturn could have a
negative impact on our results of operations.
An extended period of reduced demand for or supply of crude oil and refined products could affect our results of operations
and ability to make distributions to our unitholders.
Although we enter into throughput and deficiency agreements to protect against near-term fluctuations, our business is
ultimately dependent upon the long-term demand for and supply of the crude oil and refined products we transport in our
pipelines and store in our terminals. Any sustained decrease in demand for refined products in the markets our pipelines and
terminals serve that extends beyond the expiration of our existing throughput and deficiency agreements could result in a
significant reduction in throughputs in our pipelines and storage in our terminals, which would reduce our cash flows and our
ability to make distributions at current levels to our unitholders. Factors that could lead to a decrease in market demand include:
•
•
•
•
a recession or other adverse economic condition that results in lower spending by consumers on gasoline, diesel
and travel;
higher fuel taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of
gasoline;
an increase in automotive engine fuel economy, whether as a result of a shift by consumers to more fuel-efficient
vehicles or technological advances by manufacturers;
the increased use of alternative fuel sources;
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•
•
an increase in the market price of crude oil that leads to higher refined product prices, which may reduce demand
for refined products and drive demand for alternative products. Market prices for crude oil and refined products,
including fuel oil, are subject to wide fluctuation in response to changes in global and regional supply that are
beyond our control, and increases in the price of crude oil may result in a lower demand for refined products that
we transport, store and market, including fuel oil; and
a decrease in corn acres planted for ethanol, which may reduce demand for anhydrous ammonia.
Similarly, any sustained decrease in the supply of crude oil and refined products in markets we serve could result in a
significant reduction in throughputs in our pipelines and storage in our terminals, which would reduce our cash flows and our
ability to make distributions at current levels to our unitholders. Factors that could lead to a decrease in supply to our pipelines
and terminals include:
•
•
•
prolonged periods of low prices for crude oil and refined products, which could lead to a decrease in exploration
and development activity and reduced production in markets served by our pipelines and storage terminals;
changes in the regulatory environment, governmental policies or taxation that directly or indirectly delay
production or increase the cost of production of refined products; and
actions taken by foreign oil and gas producing nations that impact prices for crude oil and refined products.
Our inability to develop and execute growth projects and acquire new assets could limit our ability to maintain and grow
quarterly distributions to our unitholders.
Our ability to maintain and grow our distributions to unitholders depends on the growth of our existing businesses and strategic
acquisitions. Decisions regarding new growth projects rely on numerous estimates, including, among other factors, predictions
of future demand for our services, future supply shifts, crude oil production estimates, commodity price environments,
economic conditions and potential changes in the financial condition of our customers. Our predictions of such factors could
cause us to forego certain investments and to lose opportunities to competitors who make investments based on different
predictions. If we are unable to acquire new assets, due either to high prices or a lack of attractive synergistic targets, our future
growth will be limited. In addition, our future growth will be limited if we are unable to develop additional expansion projects,
implement business development opportunities and finance such activities on economically acceptable terms, which could
adversely impact our results of operations and cash flows and, accordingly, result in reduced distributions over time.
Failure to complete capital projects as planned could adversely affect our financial condition, results of operations and cash
flows.
Delays or cost increases related to capital spending programs involving construction of new facilities (or improvements and
repairs to our existing facilities) could adversely affect our ability to achieve forecasted operating results. Although we evaluate
and monitor each capital spending project and try to anticipate difficulties that may arise, such delays or cost increases may
arise as a result of factors that are beyond our control, including:
•
•
•
•
•
•
non-performance or delay by, or disputes with, counterparties, vendors, suppliers, contractors or sub-contractors
involved with a project;
denial or delay in issuing requisite regulatory approvals and/or permits;
protests and other activist interference with planned or in-process projects;
unplanned increases in the cost of construction materials or labor;
disruptions in transportation of modular components and/or construction materials;
severe adverse weather conditions, natural disasters or other events (such as equipment malfunctions, explosions,
fires or spills) affecting our facilities, or those of vendors and suppliers;
shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages; or
•
• market-related increases in a project’s debt or equity financing costs.
We will incur financing costs during the planning and construction phases of our projects; however, the operating cash flows
we expect these projects to generate will not materialize until sometime after the projects are completed, if at all. Additionally,
our forecasted operating results from capital spending projects are based upon our projections of future market fundamentals
that are not within our control, including changes in general economic conditions, the supply and demand of crude oil and
refined products, availability to our customers of attractively priced alternative solutions for storage, transportation or supplies
of crude oil and refined products and overall customer demand.
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If we are unable to retain current customers, renew existing contracts and maintain utilization of our pipeline and storage
assets or we are unable to attract new customers and enter into new contracts, in either case at current or more favorable
rates, our revenue and cash flows could be reduced to levels that could adversely affect our ability to make quarterly
distributions to our unitholders.
Our revenue and cash flows are generated primarily from our customers’ payments of fees under throughput contracts and
storage agreements. Failure to renew or enter into new contracts or our storage customers’ material reduction of utilization
under existing contracts could result from many factors, including:
•
•
•
•
•
•
•
•
•
•
continued low crude oil prices;
a material decrease in the supply or price of crude oil;
a material decrease in demand for refined products in the markets served by our pipelines and terminals;
competition for customers from companies with comparable assets and capabilities;
scheduled turnarounds or unscheduled maintenance at refineries we serve;
operational problems or catastrophic events affecting our assets or a refinery we serve;
environmental proceedings or other litigation that compel the cessation of all or a portion of the operations at our
assets or a refinery we serve;
increasingly stringent environmental, health, safety and security regulations;
a decision by our current customers to redirect refined products transported in our pipelines to markets not served
by our pipelines or to transport crude oil or refined products by means other than our pipelines; or
a decision by our current customers to sell one or more of the refineries we serve to a purchaser that elects not to
use our pipelines and terminals.
Competing midstream service providers, including certain major energy and chemical companies, possess, or have greater
financial resources to acquire, assets better suited to meet customer demand, which could undermine our ability to obtain
and retain customers or reduce utilization of our leased assets, which could reduce our revenues and cash flows, thereby
reducing our ability to make our quarterly distributions to unitholders.
Our competitors include major energy and chemical companies, some of which have greater financial resources, more pipelines
or storage terminals, greater capacity pipelines or storage terminals and greater access to supply than we do. Certain of our
competitors also may have advantages in competing for acquisitions or other new business opportunities because of their
financial resources and synergies in operations. As a consequence of increased competition in the industry, some of our
customers may be reluctant to renew or enter into long-term contracts or contracts that provide for minimum throughput
amounts in the future. Our inability to renew or replace our current contracts as they expire, to enter into contracts for newly
acquired, constructed or expanded assets and to respond appropriately to changing market conditions could have a negative
effect on our revenue, cash flows and ability to make quarterly distributions to our unitholders.
Our future financial and operating flexibility may be adversely affected by our significant leverage, any future downgrades
of our credit ratings, restrictions in our debt agreements and conditions in the financial markets.
As of December 31, 2016, our consolidated debt was $3.1 billion. We also may be required to post cash collateral under certain
of our hedging arrangements, which we expect to fund with borrowings under our revolving credit agreement. In addition to
any potential direct financial impact of our debt, it is possible that any material increase to our debt or other negative financial
factors may be viewed negatively by credit rating agencies, which could result in ratings downgrades and increased costs for us
to access the capital markets. Any downgrades in our credit ratings in the future could result in increases to the interest rates on
borrowings under our credit facilities and the 7.65% senior notes due 2018, significantly increase our capital costs, reduce our
liquidity and adversely affect our ability to raise capital in the future.
Our revolving credit agreement contains restrictive covenants, such as limitations on indebtedness, liens, mergers, asset
transfers and certain investing activities. In addition, the revolving credit agreement requires us to maintain, as of the end of
each rolling period (consisting of any period of four consecutive fiscal quarters) a consolidated debt coverage ratio
(consolidated debt to consolidated EBITDA, each as defined in the revolving credit agreement) not to exceed 5.00-to-1.00.
Failure to comply with any of the revolving credit agreement restrictive covenants or this coverage ratio will result in a default
and could result in acceleration of our obligations under this agreement and possibly other indebtedness.
Our accounts receivable securitization program contains various customary affirmative and negative covenants and default,
indemnification and termination provisions, and the related receivables financing agreement (pursuant to which we are initial
servicer and performance guarantor) provides for acceleration of amounts owed upon the occurrence of certain specified
events.
Our debt service obligations, restrictive covenants and maturities resulting from our leverage may adversely affect our ability to
finance future operations, pursue acquisitions, fund our capital needs and pay cash distributions to our unitholders at current
levels. In addition, this leverage may make our results of operations more susceptible to adverse economic or operating
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conditions. For example, during an event of default under certain of our debt agreements, we would be prohibited from making
cash distributions to our unitholders. Also, if any of our lenders file for bankruptcy or experience severe financial hardship,
they may not honor their pro rata share of our borrowing requests under the revolving credit agreement, which may
significantly reduce our available borrowing capacity and, as a result, materially adversely affect our financial condition and
ability to pay distributions to our unitholders at current levels.
Increases in interest rates could adversely affect our business and the trading price of our units.
We have significant exposure to increases in interest rates. At December 31, 2016, we had approximately $3.1 billion of
consolidated debt, of which $1.8 billion was at fixed interest rates and $1.3 billion was at variable interest rates. In addition,
prior ratings downgrades on our existing indebtedness caused interest rates under our revolving credit agreement and our senior
notes due 2018 to increase effective January 2013, and any future downgrades may cause interest rates on our variable interest
rate debt to increase further. Additionally, at December 31, 2016, we had $600.0 million aggregate notional amount of interest
rate swap arrangements, which increase our exposure to variable interest rates. As a result, our results of operations, cash flows
and financial position could be materially adversely affected by significant changes in interest rates. In addition, we historically
have funded our strategic capital expenditures and acquisitions from external sources, primarily borrowings under our
revolving credit agreement or funds raised through debt or equity offerings. An increase in interest rates may negatively impact
our ability to access the capital markets at economically attractive rates.
Furthermore, the market price of master limited partnership units, like other yield-oriented securities, may be affected by,
among other factors, implied distribution yield. The distribution yield is often used by investors to compare and rank yield-
oriented securities for investment decision-making purposes. Therefore, increases or decreases in interest rates may affect
whether or not certain investors decide to invest in our units, and a rising interest rate environment could have an adverse
impact on our unit price and our ability to issue additional equity or incur debt to expand or for other purposes or make cash
distributions at intended levels.
Depending on conditions in the credit and capital markets at a given time, we may not be able to obtain funding on
acceptable terms or at all, which may hinder or prevent us from meeting our future capital needs.
The domestic and global financial markets and economic conditions are from time to time disrupted and volatile due to a
variety of factors, including low consumer confidence, high unemployment, geoeconomic and geopolitical issues, weak
economic conditions and uncertainty in the financial services sector. In addition, there are fewer investors and lenders willing
to invest in the debt and equity capital markets in issuances by master limited partnerships than there are for more traditionally
structured corporations. As a result, the cost of raising capital in the debt and equity capital markets could increase substantially
or the availability of funds from these markets could diminish. The cost of obtaining funds from the credit markets may
increase as many lenders and institutional investors increase interest rates, enact tighter lending standards, refuse to refinance
existing debt on similar terms or at all and reduce, or in some cases cease to provide, funding to borrowers.
In addition, lending counterparties under our existing revolving credit facility and other debt instruments may be unwilling or
unable to meet their funding obligations. Due to these factors, we cannot be certain that new debt or equity financing will be
available on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, we may be
unable to execute our growth strategy, complete future acquisitions or construction projects or take advantage of other business
opportunities, any of which could have a material adverse effect on our revenues and results of operations.
Our operations are subject to operational hazards and interruptions, and we cannot insure against and/or predict all
potential losses and liabilities that might result therefrom.
Our operations and those of our customers and suppliers are subject to operational hazards and unforeseen interruptions such as
natural disasters, adverse weather, accidents, fires, explosions, hazardous materials releases, mechanical failures and other
events beyond our control. These events might result in a loss of life or equipment, injury or extensive property damage, as well
as an interruption in our operations or those of our customers or suppliers. In the event any of our facilities, or those of our
customers or suppliers, suffer significant damage or are forced to shut down for a significant period of time, it may have a
material adverse effect on our earnings, our other results of operations and our financial condition as a whole.
As a result of market conditions, premiums and deductibles for certain of our insurance policies have increased substantially
and could escalate further; therefore, we may not be able to maintain or obtain insurance of the type and amount we desire at
reasonable rates. Certain insurance coverage could become subject to broad exclusions, become unavailable altogether or
become available only for reduced amounts of coverage and at higher rates. For example, our insurance carriers require broad
exclusions for losses due to terrorist acts. If we were to incur a significant liability for which we are not fully insured, such a
liability could have a material adverse effect on our financial position.
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We could be subject to damages or lose customers due to failure to maintain certain quality specifications or other claims
related to the operation of our assets and the services we provide to our customers.
Certain of the products we store and transport are produced to precise customer specifications. If we fail to maintain the quality
and purity of the products we receive and/or a product fails to perform in a manner consistent with the quality specifications
required by the customer, the customer could seek replacement of the product or damages for costs incurred as a result of the
product failing to perform as guaranteed. We also could face other claims by our customers if our assets do not operate as
expected by our customers or our services otherwise do not meet our customers’ expectations. A successful claim or series of
claims against us could result in unforeseen expenditures and a loss of one or more customers.
We are exposed to counterparty credit risk. Nonpayment and nonperformance by our customers, vendors or derivative
counterparties could reduce our revenues, increase our expenses and otherwise have a negative impact on our ability to
conduct our business, operating results, cash flows and ability to make distributions to our unitholders.
Weak economic conditions and widespread financial stress could reduce the liquidity of our customers, vendors or
counterparties, making it more difficult for them to meet their obligations to us. We are therefore subject to risks of loss
resulting from nonpayment or nonperformance by our customers to whom we extend credit. In addition, nonperformance by
vendors who have committed to provide us with critical products or services could raise our costs or interfere with our ability to
successfully conduct our business. Furthermore, nonpayment by the counterparties to any of our outstanding derivatives could
expose us to additional interest rate or commodity price risk. Any substantial increase in the nonpayment and nonperformance
by our customers, vendors or counterparties could have a material adverse effect on our results of operations, cash flows and
ability to make distributions to unitholders.
Potential future acquisitions and expansions, if any, may increase substantially the level of our indebtedness and contingent
liabilities or otherwise change our capital structure, and we may be unable to integrate acquisitions and expansions
effectively into our existing operations.
From time to time, we evaluate and acquire assets and businesses that we believe complement or diversify our existing assets
and operations. Acquisitions may require us to raise a substantial amount of equity or incur a substantial amount of
indebtedness. If we consummate any future material acquisitions, our capitalization and results of operations may change
significantly, and unitholders will not have the opportunity to evaluate the economic, financial and other relevant information
that we will consider in connection with any future acquisitions.
Acquisitions and business expansions involve numerous risks, including difficulties in the assimilation of the assets and
operations of the acquired businesses, inefficiencies and difficulties that arise because of unfamiliarity with new assets and the
businesses associated with them and with new geographic areas. Further, unexpected costs and challenges may arise whenever
businesses with different operations or management are combined. Successful business combinations will require our
management and other personnel to devote significant amounts of time to integrating the acquired businesses with our existing
operations. These efforts may temporarily distract their attention from day-to-day business, the development or acquisition of
new properties and other business opportunities. If we do not successfully integrate any past or future acquisitions, or if there is
any significant delay in achieving such integration, our business and financial condition could be adversely affected.
Moreover, part of our business strategy includes acquiring additional assets that complement our existing asset base and
distribution capabilities or provide entry into new markets. We may not be able to identify suitable acquisitions, or we may not
be able to purchase or finance any acquisitions on terms that we find acceptable. Additionally, we compete against other
companies for acquisitions, and we may not be successful in the acquisition of any assets or businesses appropriate for our
growth strategy.
We do not own all of the land on which our pipelines and facilities have been constructed, and we are therefore subject to
the possibility of increased costs or the inability to retain necessary land use.
We obtain the rights to construct and operate our pipelines, storage terminals and other facilities on land owned by third parties
and governmental agencies. Many of our rights-of-way or other property rights are perpetual in duration while others are for a
specific period of time. In addition, some of our facilities are located on leased premises. Our loss of property rights, through
our inability to renew right-of-way contracts or leases or otherwise, could adversely affect our operations and cash flows
available for distribution to unitholders.
In addition, the construction of additions to our existing assets may require us to obtain new rights-of-way or property rights
prior to construction. We may be unable to obtain such rights-of-way or other property rights to connect new supplies to our
existing pipelines, storage terminals or other facilities or to capitalize on other attractive expansion opportunities. Additionally,
it may become more expensive for us to obtain new rights-of-way or other property rights or to renew existing rights-of-way or
property rights. If the cost of obtaining new or renewing existing rights-of-way or other property rights increases, it may
adversely affect our operations and cash flows available for distribution to unitholders.
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We may be unable to obtain or renew permits necessary for our operations, which could inhibit our ability to do business.
Our facilities operate under a number of federal, state and local permits, licenses and approvals with terms and conditions
containing a significant number of prescriptive limits and performance standards in order to operate. These limits and standards
require a significant amount of monitoring, recordkeeping and reporting in order to demonstrate compliance with the
underlying permit, license or approval. Noncompliance or incomplete documentation of our compliance status may result in the
imposition of fines, penalties and injunctive relief. In addition, public protest and responsive government intervention have
recently made it more difficult for some energy companies to acquire the permits required to complete planned infrastructure
projects. A decision by a government agency to deny or delay issuing a new or renewed permit, license or approval, or to
revoke or substantially modify an existing permit, license or approval, could have a material adverse effect on our ability to
continue operations and on our financial condition, results of operations, cash flows and ability to make distributions to our
unitholders.
We may have liabilities from our assets that preexist our acquisition of those assets, but that may not be covered by
indemnification rights we may have against the sellers of the assets.
In some cases, we have indemnified the previous owners and operators of acquired assets. Some of our assets have been used
for many years to transport and store crude oil and refined products, and releases may have occurred in the past that could
require costly future remediation. If a significant release or event occurred in the past, the liability for which was not retained
by the seller, or for which indemnification by the seller is not available, it could adversely affect our financial position and
results of operations. Conversely, if future releases or other liabilities arise from assets we have sold, we could incur costs
related to those liabilities if the buyer possesses valid indemnification rights against us with respect to those assets.
Climate change legislation and other regulatory initiatives may decrease demand for the products we store, transport and
sell and increase our operating costs.
In response to scientific studies asserting that emissions of certain “greenhouse gases” such as carbon dioxide and methane may
be contributing to warming of the Earth’s atmosphere, the U.S. Congress, European Union and other political bodies have
considered legislation or regulation to reduce emissions of greenhouse gases. Passage of climate change legislation or other
regulatory initiatives in areas in which we conduct business could result in changes to the demand for the products we store,
transport and sell, and could increase the costs of our operations, including costs to operate and maintain our facilities, install
new emission controls on our facilities, acquire allowances to authorize our greenhouse gas emissions, pay any taxes related to
our greenhouse gas emissions or administer and manage a greenhouse gas emissions program. Even though we attempt to
mitigate such lost revenues or increased costs through the contracts we sign with our customers, we may be unable to recover
those revenues or mitigate the increased costs, and any such recovery may depend on events beyond our control, including the
outcome of future rate proceedings before the FERC, the STB or other regulators and the provisions of any final legislation or
regulations. Reductions in our revenues or increases in our expenses as a result of climate control or other initiatives could
have adverse effects on our business, financial position, results of operations and prospects.
We operate a global business that exposes us to additional risk.
We operate a global business and a significant portion of our revenues come from our business outside of the United States.
Our operations outside the United States may be affected by changes in trade protection laws, policies and measures, and other
regulatory requirements affecting trade and investment, including the Foreign Corrupt Practices Act, the United Kingdom
Bribery Act and other foreign laws prohibiting corrupt payments, as well as import and export regulations. Additionally, the
decision by the United Kingdom to exit the European Union could adversely affect our operations in the United Kingdom and
in Europe; however, the nature and magnitude of any such effects are not yet apparent. We also have assets in certain emerging
markets, and the developing nature of these markets presents a number of risks. Deterioration of social, political, labor or
economic conditions, including the increasing threat of terrorist organizations and drug cartels, in a country or region in which
we do business as well as difficulties in staffing and managing foreign operations may adversely affect our operations or
financial results.
Our operations are subject to federal, state and local laws and regulations, in the U.S. and in the other countries in which
we operate, relating to environmental, health, safety and security that could require us to make substantial expenditures.
Our operations are subject to increasingly stringent federal, state and local environmental, health, safety and security laws and
regulations. Transporting, storing and distributing hazardous materials, including petroleum products, entails the risk that these
products may be released into the environment, potentially causing substantial expenditures for a response action, significant
government penalties, liability to government agencies including for damages to natural resources, personal injury or property
damages to private parties and significant business interruption. Further, certain of our pipeline facilities may be subject to the
pipeline integrity and safety regulations of various federal and state regulatory agencies. In recent years, increased regulatory
focus on pipeline integrity and safety has resulted in various proposed or adopted regulations. The implementation of these
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regulations, and the adoption of future regulations, could require us to make additional capital expenditures, including to install
new or modified safety measures, or to conduct new or more extensive maintenance programs.
Current and future legislative action and regulatory initiatives could also result in changes to operating permits, material
changes in operations, increased capital expenditures and operating costs, increased costs of the goods we transport and
decreased demand for products we handle that cannot be assessed with certainty at this time. We may be required to make
expenditures to modify operations or install pollution control equipment or release prevention and containment systems that
could materially and adversely affect our business, financial condition, results of operations and liquidity if these expenditures,
as with all costs, are not ultimately reflected in the tariffs and other fees we receive for our services.
We own or lease a number of properties that were used to transport, store or distribute products for many years before we
acquired them; therefore, such properties were operated by third parties whose handling, disposal or release of products and
wastes was not under our control. Environmental laws and regulations could impose obligations to conduct assessment or
remediation efforts at our facilities, third-party sites where we take wastes for disposal, or where wastes have migrated.
Environmental laws and regulations also may impose joint and several liability on us for the conduct of third parties or for
actions that complied with applicable requirements when taken, regardless of negligence or fault. If we were to incur a
significant liability pursuant to environmental, health, safety or security laws or regulations, such a liability could have a
material adverse effect on our financial position.
Our interstate common carrier pipelines are subject to regulation by the FERC.
The FERC regulates the tariff rates and terms and conditions of service for interstate oil movements on our common carrier
pipelines. FERC regulations require that these rates must be just and reasonable and that the pipeline not engage in undue
discrimination or undue preference with respect to any shipper. Under the ICA, the FERC or shippers may challenge our
pipeline tariff filings, including rates and terms and conditions of service. Further, other than for rates set under market-based
rate authority, if a new rate is challenged by protest and investigated by the FERC, the FERC may suspend collection of such
new rate for up to seven months. If such new rate is found to be unjust and unreasonable, the FERC may order refunds of
amounts collected in excess of amounts generated by the just and reasonable rate determined by the FERC. A successful rate
challenge could result in a common carrier paying refunds together with interest for the period that the rate was in effect. In
addition, shippers may challenge by complaint tariff rates and terms and conditions of service even after the rates and terms and
conditions of service are in effect. If the FERC, in response to such a complaint or on its own initiative, initiates an
investigation of rates that are already in effect, the FERC may order a carrier to change its rates prospectively. If existing rates
are challenged and are determined by the FERC to be in excess of a just and reasonable level, a shipper may obtain reparations
for damages sustained during the two years prior to the date the shipper filed a complaint.
We use various FERC-authorized rate change methodologies for our interstate pipelines, including indexing, cost-of-service
rates, market-based rates and settlement rates. Typically, we adjust our rates annually in accordance with the FERC indexing
methodology, which currently allows a pipeline to change its rates within prescribed ceiling levels that are tied to an inflation
index. For the five-year period beginning July 1, 2011, the index was measured by the year-over-year change in the Bureau of
Labor’s producer price index for finished goods, plus 2.65%. For the five-year period beginning July 1, 2016, the current index
is measured by the year-over-year change in the Bureau of Labor’s producer price index for finished goods, plus 1.23%.
FERC’s determination of the index for the period beginning July 1, 2016 is on appeal at the United States Court of Appeals for
the District of Columbia Circuit (D.C. Circuit), and the index for the five-year period beginning July 1, 2016 is therefore
subject to change. Further, some of our newer projects that involved an open season include negotiated indexation rate caps.
In October 2016, the FERC initiated an Advance Notice of Proposed Rulemaking (ANOPR) to determine whether to require oil
pipeline companies to file cost and revenue data for each of the company’s systems, with the definition of such systems also
part of the ANOPR. Among other things, the ANOPR also proposed that index rate adjustments be capped or prohibited under
certain circumstances and that ceiling rates be capped under certain circumstances.
These methodologies and the rulings of the D.C. Circuit could result in changes in our revenue that do not fully reflect changes
in costs we incur to operate and maintain our pipelines. For example, our costs could increase more quickly or by a greater
amount than the negotiated or, if adopted, FERC-mandated indexation rate cap.
The reporting of system-based cost and revenue data, if adopted, could lead to an increase in rate litigation at the FERC.
Generally, shippers may protest rate increases made within the ceiling levels, but such protests must show that the portion of
the rate increase resulting from application of the index is substantially in excess of the pipeline’s change in costs from the
previous year. However, if the index results in a negative adjustment, we are required to reduce any rates that exceed the new
maximum allowable rate. In addition, changes in the index might not be large enough to fully reflect actual increases in our
costs. If the FERC’s rate-making methodologies change, any such change or new methodologies could result in rates that
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generate lower revenues and cash flow and could adversely affect our ability to make distributions at current levels to our
unitholders and to meet our debt service requirements. Additionally, competition constrains our rates in various markets. As a
result, we may from time to time be forced to reduce some of our rates to remain competitive.
Changes to FERC rate-making principles could have an adverse impact on our ability to recover the full cost of operating
our pipeline facilities and our ability to make distributions at current levels to our unitholders.
In May 2005, the FERC issued a statement of general policy stating it will permit pipelines to include in their costs of service a
tax allowance to reflect actual or potential tax liability on their public utility income attributable to all partnership or limited
liability company interests, if the ultimate owner of the interest has an actual or potential income tax liability on such income.
Whether a pipeline’s owners have such actual or potential income tax liability will be reviewed by the FERC on a case-by-case
basis. Although this policy is generally favorable for pipelines that are organized as pass-through entities, it still entails rate risk
due to the case-by-case review requirement. This tax allowance policy and the FERC’s application of that policy were appealed
to the D.C. Circuit and, on May 29, 2007, the D.C. Circuit issued an opinion upholding the FERC’s tax allowance policy.
In two proceedings involving SFPP, L.P., a refined products pipeline system, shippers again challenged the FERC’s income tax
allowance policy, alleging that it is unlawful for a pipeline organized as a tax-pass-through entity to be afforded an income tax
allowance and that the income tax allowance is unnecessary because an allowance for income taxes for such pipelines is
recovered indirectly through the rate of return on equity. The FERC rejected these shipper arguments in multiple orders.
Petitions for review of the FERC’s rulings on the income tax allowance were filed with the D.C. Circuit.
On July 1, 2016, the D.C. Circuit issued an opinion granting the shippers’ petition for review of the FERC’s rulings on the
income tax allowance, finding that the FERC had failed to demonstrate that there was no double recovery of taxes for
partnerships that receive an income tax allowance in addition to the return they receive through the rate of return on equity. On
this basis, the D.C. Circuit has remanded the issue back to the FERC and the FERC has established an industrywide Notice of
Inquiry regarding this issue. Because the extent to which an interstate oil pipeline organized as a partnership is entitled to an
income tax allowance is subject to a case-by-case review at the FERC and is a matter that remains under litigation and FERC
review, the level of income tax allowance to which we would ultimately be entitled in a cost-of-service rate review is not
certain. How the FERC’s income tax allowance policy is applied in practice to pipelines owned by publicly traded partnerships
could impose limits on our ability to include a full income tax allowance in our cost of service.
The rates that we may charge on our interstate ammonia pipeline are subject to regulation by the STB.
The Ammonia Pipeline is subject to regulation under the ICA by the STB. Under that regulation the Ammonia Pipeline’s rates,
classifications, rules and practices related to the interstate transportation of anhydrous ammonia must be reasonable and, in
providing interstate transportation, our ammonia pipeline may not subject a person, place, port or type of traffic to unreasonable
discrimination.
Increases in natural gas and power prices could adversely affect our operating expenses and our ability to make
distributions at current levels to our unitholders.
Power costs constitute a significant portion of our operating expenses. For the year ended December 31, 2016, our power costs
equaled approximately $43.1 million, or 9.6% of our operating expenses for the year. We use mainly electric power at our
pipeline pump stations and terminals, and such electric power is furnished by various utility companies that primarily use
natural gas to generate electricity. Accordingly, our power costs typically fluctuate with natural gas prices, and increases in
natural gas prices may cause our power costs to increase further. If natural gas prices increase, our cash flows may be adversely
affected, which could adversely affect our ability to make distributions to our unitholders.
Terrorist attacks (and cyberattacks) and the threat of future attacks worldwide, as well as continued hostilities in the Middle
East or other sustained military campaigns, may adversely impact our results of operations.
Increased security measures we have taken as a precaution against possible terrorist and cyberattacks have resulted in increased
costs to our business. Uncertainty surrounding continued hostilities in the Middle East or other sustained military campaigns
may affect our operations in unpredictable ways, including disruptions of crude oil supplies and markets for refined products,
instability in the financial markets that could restrict our ability to raise capital and the possibility that infrastructure facilities
could be direct targets of, or indirect casualties of, an attack.
The United States Department of Homeland Security has identified pipelines and other energy infrastructure assets as ones that
might be specific targets of terrorist organizations or breaches of cybersecurity. These potential targets might include our
pipeline systems, storage facilities or operating systems and may affect our ability to operate or control our pipeline and storage
assets. Our systems and networks, as well as those of our customers, suppliers, vendors and counterparties, may become the
target of cyberattacks or information security breaches, which in turn could result in the unauthorized release and misuse of
confidential and proprietary information as well as disrupt our operations, damage our facilities or those of third parties or harm
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our reputation. Any failure or disruption of our systems could cause a substantial decrease in revenues, increased costs to
respond or other financial loss, damage to reputation, increased regulation or litigation and/or inaccurate information reported
from our operations. These developments may subject our operations to increased risks, as well as increased costs, and,
depending on their ultimate magnitude, could have a material adverse effect on our business, results of operations and financial
condition.
Hedging transactions may limit our potential gains or result in significant financial losses.
While intended to reduce the effects of volatile commodity prices, hedging transactions, depending on the hedging instrument
used, may limit our potential gains if petroleum product prices were to rise substantially over the price established by the
hedge. In addition, such transactions may expose us to the risk of financial loss in certain circumstances, including instances in
which:
•
•
the counterparties to our hedging contracts fail to perform under the contracts; or
there is a change in the expected differential between the underlying price in the hedging agreement and the actual
prices received.
The accounting standards regarding hedge accounting are complex and, even when we engage in hedging transactions that are
effective economically, these transactions may not be considered effective for accounting purposes. Accordingly, our financial
statements will reflect increased volatility due to these hedges, even when there is no underlying economic impact at that point.
It is not possible for us to engage in a hedging transaction that completely mitigates our exposure to commodity prices, and our
financial statements may reflect a gain or loss arising from an exposure to commodity prices for which we are unable to enter
into an effective hedge.
Our purchase and sale of crude oil and petroleum products may expose us to trading losses and hedging losses, and non-
compliance with our risk management policies could result in significant financial losses.
Although our marketing and trading of crude oil and petroleum products represents a small percentage of our overall business,
these activities expose us to some commodity price volatility risk for the purchase and sale of crude oil and petroleum products,
including distillates and fuel oil. We attempt to mitigate this volatility risk through hedging, but we are still exposed to basis
risk and may be required to post cash collateral under our hedging arrangements. We also may be exposed to inventory and
financial liquidity risk due to the inability to trade certain products or rising costs of carrying some inventories. Further, our
marketing and trading activities, including any hedging activities, may cause volatility in our earnings. In addition, we will be
exposed to credit risk in the event of non-performance by counterparties.
Our risk management policies may not eliminate all price risk since open trading positions will expose us to price volatility, and
there is a risk that our risk management policies will not be complied with. Although we have designed procedures to anticipate
and detect non-compliance, we cannot assure you that these steps will detect and prevent all violations of our trading policies
and procedures, particularly if deception and other intentional misconduct are involved.
If we fail to maintain an effective system of internal controls, we may not be able to report our financial results accurately
or prevent fraud, which could have a material and adverse impact on our financial condition, results of operations, cash
flows and ability to make distributions to our unitholders.
Under Section 404 of the Sarbanes-Oxley Act of 2002, we are required to disclose material changes made in our internal
controls over financial reporting on a quarterly basis and we are required to assess the effectiveness of our controls annually.
Effective internal controls are necessary for us to provide reliable and timely financial reports, to prevent fraud and to operate
successfully as a publicly traded limited partnership. Given the difficulties inherent in the design and operation of internal
controls over financial reporting, we may be unable to maintain effective controls over our financial processes and reporting in
the future or to comply with our obligations under Section 404.
For the foregoing reasons, we can provide no assurance as to our, or our independent registered public accounting firm’s, future
conclusions about the effectiveness of our internal controls, and we may incur significant costs in our efforts to comply with
Section 404. Any failure to maintain effective internal controls over financial reporting will subject us to regulatory scrutiny
and a loss of confidence in our reported financial information, which could have a material adverse effect on our financial
condition, results of operations and cash flows and our ability to make distributions to our unitholders.
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RISKS INHERENT IN AN INVESTMENT IN US
We do not have the same flexibility as other types of organizations to accumulate cash and equity and protect against
illiquidity in the future.
Unlike a corporation, our partnership agreement requires us to make quarterly distributions to our unitholders of all available
cash, after taking into account reserves for commitments and contingencies, including capital and operating costs and debt
service requirements. As a result, we do not accumulate equity in the form of retained earnings in a manner typical of many
other forms of organizations, including most traditional public corporations. We are therefore more likely than those
organizations to require issuances of additional capital to finance our growth plans, meet unforeseen cash requirements and
service our debt.
Additionally, the value of our common units and other limited partner interests may decrease in correlation with any reduction
in our cash distributions per unit. Accordingly, if we experience a liquidity shortage in the future, we may not be able to issue
more equity to recapitalize.
Our cash distribution policy may limit our growth.
Consistent with the terms of our partnership agreement, we distribute our available cash to our unitholders each quarter. In
determining the amount of cash available for distribution, our management sets aside cash reserves which we use to fund our
growth capital expenditures. Additionally, we historically have relied upon external financing sources, including commercial
borrowings and other debt and equity issuances, to fund our acquisition capital expenditures. Accordingly, to the extent we do
not have sufficient cash reserves or are unable to finance growth externally, our cash distribution policy will significantly
impair our ability to grow. In addition, to the extent we issue additional units in connection with any acquisitions or growth
capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to
maintain or increase our current per unit distribution level.
NuStar GP Holdings may have conflicts of interest and limited fiduciary responsibilities, which may permit it to favor its
own interests to the detriment of our unitholders.
NuStar GP Holdings currently indirectly owns our general partner and, as of December 31, 2016, an aggregate 13.0% common
limited partner interest in us. Conflicts of interest may arise between NuStar GP Holdings and its affiliates, including our
general partner, on the one hand, and us and our limited partners, on the other hand. As a result of these conflicts, the general
partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. These conflicts include,
among others, the following situations:
•
•
•
•
•
•
•
our general partner is allowed to take into account the interests of parties other than us, such as NuStar GP
Holdings, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders;
our general partner may limit its liability and reduce its fiduciary duties, while also restricting the remedies
available to unitholders. As a result of purchasing our units, unitholders have consented to some actions and
conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state
law;
our general partner determines the amount and timing of asset purchases and sales, capital expenditures,
borrowings and issuances of additional limited partner interests and reserves, each of which can affect the amount
of cash that is paid to our unitholders;
our general partner determines in its sole discretion which costs incurred by NuStar GP Holdings and its affiliates
are reimbursable by us;
our general partner may cause us to pay the general partner or its affiliates for any services rendered on terms that
are fair and reasonable to us or enter into additional contractual arrangements with any of these entities on our
behalf;
our general partner decides whether to retain separate counsel, accountants or others to perform services for us;
and
in some instances, our general partner may cause us to borrow funds in order to permit the payment of
distributions.
Our partnership agreement gives the general partner broad discretion in establishing financial reserves for the proper conduct of
our business, including interest payments. These reserves also affect the amount of cash available for distribution.
The general partner interest, the control of our general partner and the incentive distribution rights of our general partner
may be transferred to a third party without unitholder consent.
Our general partner may transfer its general partner interest and/or its incentive distribution rights to a third party without the
consent of our unitholders. Any new owner of our general partner would be in a position to replace the officers of the general
partner with its own choices and to control the decisions made by such officers. If our general partner transfers its incentive
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distribution rights to a third party but retains its general partner interest, our general partner may not have the same incentive to
grow our partnership and increase quarterly distributions to unitholders over time as it would if it had retained ownership of its
incentive distribution rights.
We may issue an unlimited number of additional units, including units that are senior to the common units and pari passu
with our 8.50% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the Preferred Units);
issuing new units dilutes existing unitholders and may increase the aggregate distribution we are required to pay each
quarter under the terms of our partnership agreement.
Our partnership agreement allows us to issue additional units and certain other equity securities on the terms and conditions
established by our general partner and without the approval of other unitholders. There is no limit on the total number of units
and other equity securities we may issue. If we issue additional units or other equity securities, the proportionate partnership
interest of our existing common unitholders and the relative voting strength of each of the previously outstanding common
units will decrease. Any additional issuance may increase the risk that we will be unable to maintain or increase our per
common unit distribution level.
In addition, we may issue an unlimited number of units that are senior to the common units in right of distribution, liquidation
and voting, including additional Preferred Units and any securities in parity with the Preferred Units without any vote of the
holders of the Preferred Units (except where the cumulative distributions on the Preferred Units or any parity securities are in
arrears and in certain other circumstances) and without the approval of our common unitholders. Our issuance of additional
units or other equity interests of equal or senior rank will have the following effects:
•
•
•
•
•
our unitholders’ proportionate ownership interest in us will decrease;
the amount of cash available for distribution on each unit may decrease;
the ratio of taxable income to distributions may increase;
the relative voting strength of each previously outstanding unit may be diminished; and
the market price of our common units and Preferred Units may decline.
Additionally, although holders of the Preferred Units are entitled to limited voting rights, with respect to certain matters the
Preferred Units generally vote separately as a class along with all other series of our parity securities that we may issue upon
which like voting rights have been conferred and are exercisable. As a result, the voting rights of holders of Preferred Units
may be significantly diluted, and the holders of such other series of parity securities that we may issue may be able to control or
significantly influence the outcome of any vote. The issuance of additional units on parity with or senior to the Preferred Units
(including additional Preferred Units of the same series) would dilute the interests of the holders of the Preferred Units, and any
issuance of equity securities of any class or series that ranks on parity with the Preferred Units as to the payment of
distributions and amounts payable upon a liquidation event (including additional Preferred Units of the same series) or equity
securities with terms expressly made senior to the Preferred Units as to the payment of distributions and amounts payable upon
a liquidation event or additional indebtedness could affect our ability to pay distributions on, redeem or pay the liquidation
preference on the Preferred Units. Only the change of control conversion right relating to the Preferred Units set forth in our
partnership agreement protects the holders of the Preferred Units in the event of a highly leveraged or other transaction,
including a merger or the sale, lease or conveyance of all or substantially all of our assets or business, which might adversely
affect the holders of the Preferred Units.
Future issuances and sales of parity securities, or the perception that such issuances and sales could occur, may cause prevailing
market prices for the Preferred Units and our common units to decline and may adversely affect our ability to raise additional
capital in the financial markets at times and prices favorable to us.
Furthermore, the payment of distributions on any additional units may increase the risk that we will not be able to make
distributions at our prior per unit distribution levels. To the extent new units are senior to our common units, their issuance will
increase the uncertainty of the payment of distributions on our common units.
If we do not pay distributions on our Preferred Units in any fiscal quarter, we will be unable to pay distributions on our
common units until all unpaid Preferred Unit distributions have been paid, and our common unitholders are not entitled to
receive distributions for such prior period.
The Preferred Units rank senior to our common units with respect to distribution rights and rights upon liquidation. If we do not
pay the required distributions on our Preferred Units, we will be unable to pay distributions on our common units. Additionally,
because distributions to our Preferred Unitholders are cumulative, we will have to pay all unpaid accumulated preferred
distributions before we can pay any distributions to our common unitholders. Also, because distributions to our common
unitholders are not cumulative, if we do not pay distributions on our common units with respect to any quarter, our common
unitholders will not be entitled to receive distributions covering any prior periods. The preferences and privileges of the
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Preferred Units could adversely affect the market price for our common units, or could make it more difficult for us to sell our
common units in the future.
Unitholders may not have limited liability if a court finds that unitholder action constitutes control of our business or that
we have not complied with applicable statutes, which may have an impact on the cash we have available to make
distributions.
Under Delaware law, unitholders could be held liable for our obligations to the same extent as a general partner if a court
determined that actions of a unitholder constituted participation in the “control” of our business.
Under Delaware law, the general partner generally has unlimited liability for the obligations of the partnership, such as its debts
and environmental liabilities, except for those contractual obligations of the partnership that are expressly made without
recourse to the general partner. In addition, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act (the
Delaware Act) provides that, under some circumstances, a limited partner may be liable to us for the amount of a distribution
for a period of three years from the date of the distribution.
Under certain circumstances, unitholders may have liability to repay distributions wrongfully distributed to them.
Under Section 17-607 of the Delaware Act, we may not make a distribution to our unitholders if the distribution would cause
our liabilities to exceed the fair value of our assets. Liabilities to partners on account of their partnership interests and liabilities
that are nonrecourse to the partnership are not counted for purposes of determining whether a distribution is permitted.
Delaware law provides that, for a period of three years from the date of an impermissible distribution, limited partners who
received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to us for the
repayment of the distribution amount. Likewise, upon the winding up of our partnership, in the event that (a) we do not
distribute assets in the following order: (1) to creditors in satisfaction of our debts; (2) to partners and former partners in
satisfaction of liabilities for distributions owed under our partnership agreement; (3) to partners for the return of their
contributions; and finally (4) to the partners in the proportions in which the partners share in distributions and (b) a limited
partner knows at the time that the distribution violated the Delaware Act, then such limited partner will be liable to repay the
distribution for a period of three years from the impermissible distribution under Section 17-804 of the Delaware Act.
A purchaser of common or Preferred Units becomes a limited partner and is liable for the obligations of the transferring limited
partner to make contributions to us that are known to such purchaser of common or Preferred Units at the time it became a
limited partner and for unknown obligations, if the liabilities could be determined from our partnership agreement.
Unitholders may be required to sell their units to our general partner at an undesirable time or price.
If at any time less than 20% of the outstanding units of any class are held by persons other than the general partner and its
affiliates, the general partner will have the right to acquire all, but not less than all, of those units at a price no less than their
then-current market price. As a consequence, a unitholder may be required to sell his common units at an undesirable time or
price. The general partner may assign this purchase right to any of its affiliates or to us.
The NYSE does not require a publicly traded limited partnership like us to comply with certain of its corporate governance
requirements.
We currently list our common units on the NYSE under the symbol “NS” and our Preferred Units on the NYSE under the
symbol “NSprA.” Although our general partner has maintained a majority of independent directors on its board and all
members of its board’s audit committee, compensation committee and nominating/governance & conflicts committee are
independent directors, because we are a publicly traded limited partnership, the NYSE does not require us to have a majority of
independent directors on our general partner’s board of directors or to have a compensation committee or a nominating
committee consisting of independent directors. Additionally, any future issuance of additional common or Preferred Units or
other securities, including to affiliates, will not be subject to the NYSE’s shareholder approval rules that apply to a corporation.
Accordingly, the NYSE does not mandate the same protections for our unitholders as are required for certain corporations that
are subject to all of the NYSE corporate governance requirements. See “Director Independence” under Item 13 of this annual
report on Form 10-K for additional information regarding the independence of our general partner’s directors and the
committees of our general partner’s board.
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TAX RISKS TO OUR UNITHOLDERS
If we were treated as a corporation for federal or state income tax purposes or we were otherwise subject to a material
amount of entity-level taxation, then our cash available for distribution to unitholders would be substantially reduced.
The anticipated after-tax benefit of an investment in our units depends largely on our being treated as a partnership for federal
income tax purposes. We have not requested, and do not plan to request, a ruling from the Internal Revenue Service (the IRS)
on this matter.
Despite the fact that we are a limited partnership under Delaware law, we will be treated as a corporation for federal income tax
purposes unless we satisfy a “qualifying income” requirement. Based upon our current operations, we believe we satisfy the
qualifying income requirement. Failing to meet the qualifying income requirement or a change in current law could cause us to
be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at
the corporate tax rate, which is currently a maximum of 35%, and would likely pay state and local income tax at varying rates.
Distributions to unitholders who are treated as holders of corporate stock would generally be taxed again as corporate dividends
(to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions or credits would
flow through to unitholders. Because a tax would be imposed upon us as a corporation, our distributable cash flow would be
substantially reduced.
Moreover, changes in current state law may subject us to entity-level taxation by individual states. Because of widespread state
budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the
imposition of state income, franchise and other forms of taxation. Imposition of any such taxes or an increase in the existing tax
rates would substantially reduce the cash available for distribution to our unitholders. Therefore, if we were treated as a
corporation for federal income tax purposes or otherwise subjected to a material amount of entity-level taxation, there would be
a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in
the value of our units.
The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative,
judicial or administrative changes or differing interpretations, possibly applied on a retroactive basis.
The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our units may
be modified by administrative, legislative or judicial changes or differing interpretations at any time. From time to time,
members of Congress propose and consider such substantive changes to the existing federal income tax laws that affect
publicly traded partnerships. Further, final Treasury regulations under Section 7704(d)(1)(E) of the Code recently published in
the Federal Register interpret the scope of qualifying income requirements for publicly traded partnerships by providing
industry-specific guidance.
Any modification to the federal income tax laws may be applied retroactively and could make it more difficult or impossible
for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for federal income tax
purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted, including as a
result of fundamental tax reform. Any such changes could negatively impact the value of an investment in our units.
A successful IRS contest of the federal income tax positions we take may adversely impact the market for our units, and the
costs of any contest will reduce cash available for distribution to our unitholders.
The IRS may adopt positions that differ from the positions we take, even positions taken with the advice of counsel. It may be
necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree
with all of the positions we take. Any contest with the IRS may affect adversely the taxable income reported to our unitholders
and the income taxes they are required to pay. As a result, any such contest with the IRS may materially and adversely impact
the market for our units and the prices at which they trade. In addition, the costs of any contest between us and the IRS will be
borne indirectly by our unitholders and our general partner because such costs will reduce our cash available for distribution.
Legislation applicable to partnership tax years beginning after 2017 alters the procedures for auditing large partnerships and for
assessing and collecting taxes due (including penalties and interest) as a result of a partnership-level federal income tax audit.
Under these rules, unless we are eligible to, and do, elect to issue revised Schedules K-1 to our partnership with respect to an
audited and adjusted partnership tax return, the IRS may assess and collect taxes (including any applicable penalties and
interest) directly from us in the year in which the audit is completed. If we are required to pay taxes, penalties and interest as a
result of audit adjustments, cash available for distribution to our unitholders may be substantially reduced. In addition, because
payment would be due for the taxable year in which the audit is completed, unitholders during that taxable year would bear the
expense of the adjustment even if they were not unitholders during the audited tax year.
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Even if unitholders do not receive any cash distributions from us, they will be required to pay taxes on their respective share
of our taxable income.
Unitholders will be required to pay federal income taxes and, in some cases, state and local income taxes on their respective
share of our taxable income, whether or not the unitholders receive cash distributions from us. Unitholders may not receive
cash distributions from us equal to their respective share of our taxable income or even equal to the actual tax liability that
results from their respective share of our taxable income.
The sale or exchange of 50% or more of our capital and profits interests, within a twelve-month period, will result in the
termination of our partnership for federal income tax purposes.
We will be considered to have terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the
total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold
has been met, multiple sales of the same interest will be counted only once.
Our termination for federal income tax purposes would, among other things, result in the closing of our taxable year for all
unitholders, which would result in us filing two tax returns for one calendar year and could result in a significant deferral of
depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year
other than a calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income or
loss being includable in taxable income for the unitholder’s taxable year that includes our termination. Our termination would
not affect our classification as a partnership for federal income tax purposes, but it would result in our being treated as a new
partnership for U.S. federal income tax purposes following the termination. If we were treated as a new partnership, we would
be required to make new tax elections and could be subject to penalties if we were unable to determine that a termination
occurred. The IRS has announced a relief procedure whereby if a publicly traded partnership that has technically terminated
requests, and the IRS grants, special relief, among other things, the partnership may be permitted to provide only a single
Schedule K-1 to unitholders for the two short tax periods included in the year in which the termination occurs.
Tax gain or loss on the disposition of our units could be different than expected.
If a unitholder sells units, the selling unitholder will recognize a gain or loss equal to the difference between the amount
realized and the unitholder’s tax basis in those units. Prior distributions to the selling unitholder in excess of the total net
taxable income the unitholder was allocated for a unit, which decreased the unitholder’s tax basis in that unit, will, in effect,
become taxable income to the selling unitholder if the unit is sold at a price greater than the unitholder’s tax basis in that unit,
even if the price the unitholder receives is less than the unit’s original cost. A substantial portion of the amount realized,
whether or not representing gain, may be ordinary income to the selling unitholder.
Tax-exempt entities and foreign persons face unique tax issues from owning common units that may result in adverse tax
consequences to them.
Investment in common units by tax-exempt entities, such as individual retirement accounts (known as IRAs) and non-United
States persons raises issues unique to them. For example, virtually all of our income allocated to organizations exempt from
federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to
them. Distributions to non-United States persons will be reduced by withholding taxes at the highest applicable effective tax
rate, and non-United States persons will be required to file United States federal income tax returns and pay tax on their share
of our taxable income.
We will treat each purchaser of our common units as having the same tax benefits without regard to the units purchased.
The IRS may challenge this treatment, which could adversely affect the value of our common units.
Because we cannot match transferors and transferees of our common units, we will adopt depreciation and amortization
positions that may not conform with all aspects of existing Treasury regulations. A successful IRS challenge to those positions
could adversely affect the amount of tax benefits available to unitholders. It also could affect the timing of these tax benefits or
the amount of gain from a unitholder’s sale of common units and could have a negative impact on the value of our common
units or result in audit adjustments to the unitholder’s tax returns.
Unitholders will likely be subject to state and local taxes and return filing requirements as a result of investing in our units.
In addition to federal income taxes, unitholders will likely be subject to other taxes, such as state and local income taxes,
unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which
we do business or own property. Unitholders will likely be required to file state and local income tax returns and pay state and
local income taxes in some or all of these various jurisdictions. Further, unitholders may be subject to penalties for failure to
comply with those requirements. We may own property or conduct business in other states or foreign countries in the future. It
is each unitholder’s responsibility to file all federal, state and local tax returns.
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We prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each
month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a
particular common unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of
income, gain, loss and deduction among our common unitholders.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month
based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular
common unit is transferred. The U.S. Treasury Department and the IRS recently issued final regulations pursuant to which a
publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and
transferee unitholders, although such tax items must be prorated on a daily basis and the regulations do not specifically
authorize all aspects of the proration method we have currently adopted. If the IRS were to challenge our proration method, we
may be required to change the allocation of items of income, gain, loss and deduction among our common unitholders.
We have adopted certain valuation methodologies in determining a common unitholder’s allocations of income, gain, loss
and deduction. The IRS may challenge these methods or the resulting allocations and such a challenge could adversely
affect the value of our common units.
In determining the items of income, gain, loss and deduction allocable to our common unitholders, we must routinely determine
the fair market value of our respective assets. Although we may from time to time consult with professional appraisers
regarding valuation matters, we make fair market value estimates using a methodology based on the market value of our
common units as a means to measure the fair market value of our respective assets. The IRS may challenge these valuation
methods and the resulting allocations of income, gain, loss and deduction.
A successful IRS challenge to these methods or allocations could adversely affect the amount, character and timing of taxable
income or loss being allocated to our common unitholders. It also could affect the amount of gain from our unitholders’ sale of
common units and could have a negative impact on the value of the common units or result in audit adjustments to our common
unitholders’ tax returns without the benefit of additional deductions.
A unitholder whose units are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of units)
may be considered as having disposed of those units. If so, the unitholder would no longer be treated for tax purposes as a
partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.
Because there are no specific rules governing the federal income tax consequences of loaning a partnership interest, a
unitholder whose units are the subject of a securities loan may be considered as having disposed of the loaned units. In that
case, the unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the
loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the
loan, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any
cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to
assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax
advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from
borrowing their units.
Treatment of distributions on our Preferred Units as guaranteed payments for the use of capital creates a different tax
treatment for the holders of Preferred Units than the holders of our common units.
The tax treatment of distributions on our Preferred Units is uncertain. We will treat the holders of Preferred Units as partners
for tax purposes and will treat distributions on the Preferred Units as guaranteed payments for the use of capital that will
generally be taxable to the holders of Preferred Units as ordinary income. Although a holder of Preferred Units could recognize
taxable income from the accrual of such a guaranteed payment even in the absence of a contemporaneous distribution, we
anticipate accruing and making the guaranteed payment distributions quarterly. Otherwise, the holders of Preferred Units are
generally not anticipated to share in our items of income, gain, loss or deduction, nor will we allocate any share of our
nonrecourse liabilities to the holders of Preferred Units. If the Preferred Units were treated as indebtedness for tax purposes,
rather than as guaranteed payments for the use of capital, distributions likely would be treated as payments of interest by us to
the holders of Preferred Units.
A holder of Preferred Units will be required to recognize gain or loss on a sale of Preferred Units equal to the difference
between the amount realized by such holder and tax basis in the Preferred Units sold. The amount realized generally will equal
the sum of the cash and the fair market value of other property such holder receives in exchange for such Preferred Units.
Subject to general rules requiring a blended basis among multiple partnership interests, the tax basis of a Preferred Unit will
generally be equal to the sum of the cash and the fair market value of other property paid by the holder of Preferred Units to
acquire such Preferred Unit. Gain or loss recognized by a holder of Preferred Units on the sale or exchange of a Preferred Unit
held for more than one year generally will be taxable as long-term capital gain or loss. Because holders of Preferred Units will
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generally not be allocated a share of our items of depreciation, depletion or amortization, it is not anticipated that such holders
would be required to recharacterize any portion of their gain as ordinary income as a result of the recapture rules.
Investment in the Preferred Units by tax-exempt investors, such as employee benefit plans and IRAs, and non-U.S. persons
raises issues unique to them. Distributions to non-U.S. holders of Preferred Units will be subject to withholding taxes. If the
amount of withholding exceeds the amount of U.S. federal income tax actually due, non-U.S. holders of Preferred Units may be
required to file U.S. federal income tax returns in order to seek a refund of such excess. The treatment of guaranteed payments
for the use of capital to tax exempt investors is not certain and such payments may be treated as unrelated business taxable
income for federal income tax purposes. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax
advisor with respect to the consequences of owning our Preferred Units.
PROPERTIES
Our principal properties are described above under the caption “Segments,” and that information is incorporated herein by
reference. We believe that we have satisfactory title to all of our properties. Although title to these properties is subject to
encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property,
liens for current taxes and other burdens and easements, and restrictions or other encumbrances, including those related to
environmental liabilities associated with historical operations, to which the underlying properties were subject at the time of
acquisition by us or our predecessors, we believe that none of these burdens will materially detract from the value of these
properties or from our interest in these properties or will materially interfere with their use in the operation of our business. In
addition, we believe that we have obtained sufficient right-of-way grants and permits from public authorities and private parties
for us to operate our business in all material respects as described in this report. We perform scheduled maintenance on all of
our pipelines, terminals, crude oil tanks and related equipment and make repairs and replacements when necessary or
appropriate. We believe that our pipelines, terminals, crude oil tanks and related equipment have been constructed and are
maintained in all material respects in accordance with applicable federal, state and local laws and the regulations and standards
prescribed by the American Petroleum Institute, the DOT and accepted industry practice.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 3.
LEGAL PROCEEDINGS
We are named as a defendant in litigation and are a party to other claims and legal proceedings relating to our normal business
operations, including regulatory and environmental matters. Due to the inherent uncertainty of litigation, there can be no
assurance that the resolution of any particular claim or proceeding would not have a material adverse effect on our results of
operations, financial position or liquidity.
We are insured against various business risks to the extent we believe is prudent; however, we cannot assure you that the nature
and amount of such insurance will be adequate, in every case, to protect us against liabilities arising from future legal
proceedings as a result of our ordinary business activity.
ENVIRONMENTAL AND SAFETY COMPLIANCE MATTERS
Our wholly owned subsidiary, Shore Terminals LLC (Shore), owns a refined product terminal in Portland, Oregon located
adjacent to the Portland Harbor. The EPA has classified portions of the Portland Harbor, including the portion adjacent to our
terminal, as a federal “Superfund” site due to sediment contamination (the Site). As previously disclosed, Shore and more than
90 other parties have been identified as potentially responsible parties (PRPs) in connection with the Site. Shore has been
working with the other PRPs to attempt to negotiate an agreed allocation of clean-up costs and settlement of natural resource
damage claims. Although the PRP group as a whole is likely to incur significant costs in connection with the Site, we have
determined that: (1) this matter will not likely be material to our business or financial condition or have a material effect on our
consolidated financial position; (2) Shore’s allocation among the PRP group is likely to be de minimus and we believe we have
sufficient insurance coverage to respond to this potential liability; and (3) we do not believe that this matter will result in an
assessment of monetary sanctions against Shore.
ITEM 4.
MINE SAFETY DISCLOSURES
Not applicable.
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PART II
ITEM 5.
MARKET FOR REGISTRANT’S COMMON UNITS, RELATED UNITHOLDER MATTERS AND
ISSUER PURCHASES OF EQUITY SECURITIES
Our common units are listed and traded on the New York Stock Exchange under the symbol “NS.” At the close of business on
February 8, 2017, we had 506 holders of record of our common units. The following table presents the high and low sales
prices for our common units during the periods presented (composite transactions as reported by the New York Stock
Exchange) and the amount, record date and payment date of the quarterly cash distributions on our common units with respect
to such periods:
Price Range per Common Unit
Cash Distributions
High
Low
Amount Per
Common Unit
Record Date
Payment Date
$
$
$
$
$
$
$
$
50.87
50.72
53.47
42.87
52.24
60.48
68.10
63.78
$
$
$
$
$
$
$
$
43.41
43.91
37.90
25.65
31.20
42.00
58.81
54.58
$
$
$
$
$
$
$
$
1.095
1.095
1.095
1.095
1.095
1.095
1.095
1.095
February 8, 2017
February 13, 2017
November 8, 2016
November 14, 2016
August 9, 2016
August 12, 2016
May 9, 2016
May 13, 2016
February 8, 2016
February 12, 2016
November 9, 2015
November 13, 2015
August 7, 2015
August 13, 2015
May 8, 2015
May 14, 2015
Year 2016
4th Quarter
3rd Quarter
2nd Quarter
1st Quarter
Year 2015
4th Quarter
3rd Quarter
2nd Quarter
1st Quarter
Common Unit Distributions
Our partnership agreement requires that we distribute all “Available Cash” to our common limited partners and general partner
each quarter, and this term is defined in the partnership agreement generally as cash on hand at the end of the quarter, plus
certain permitted borrowings made subsequent to the end of the quarter, less cash reserves determined by our board of
directors. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for further
information regarding our distributions.
General Partner Distributions
Our general partner is entitled to incentive distributions if the amount that we distribute with respect to any quarter exceeds
specified target levels shown below:
Quarterly Distribution Amount per Common Unit
Up to $0.60
Above $0.60 up to $0.66
Above $0.66
Percentage of Distribution
Common
Unitholders
98%
90%
75%
General
Partner
2%
10%
25%
Our general partner’s incentive distributions totaled $43.4 million and $43.2 million for each of the years ended December 31,
2016 and 2015, respectively. The general partner’s share of our distributions for the years ended December 31, 2016 and 2015
was 13.0% in each year due to the impact of the incentive distributions.
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Preferred Unit Distributions
In the fourth quarter of 2016, we issued 9,060,000 of our 8.50% Series A Fixed-to-Floating Rate Cumulative Redeemable
Perpetual Preferred Units (the Preferred Units) representing limited partner interests at a price of $25.00 per unit. We used the
net proceeds of $218.4 million from this issuance for general partnership purposes, including the funding of capital
expenditures and repayments of outstanding borrowings under our revolving credit agreement.
Distributions on the Preferred Units are payable out of any legally available funds, accrue and are cumulative from the date of
original issuance of the Preferred Units and are payable on the 15th day of each of March, June, September and December of
each year (beginning on March 15, 2017) to holders of record on the first day of each payment month. The initial distribution
rate on the Preferred Units to, but not including, December 15, 2021 is 8.50% per annum of the $25.00 liquidation preference
per unit (equal to $2.125 per unit per annum). On and after December 15, 2021, distributions on the Preferred Units
accumulate at a percentage of the $25.00 liquidation preference equal to an annual floating rate of the three-month LIBOR plus
a spread of 6.766%. On January 27, 2017, we announced a Preferred Unit distribution of $0.64930556 per unit to be paid on
March 15, 2017 to holders of record as of March 1, 2017 for distributions accumulated from the issuance date up to the
payment date. The Preferred Units rank senior to all of our other classes of equity securities with respect to distribution rights
and rights upon liquidation.
ITEM 6.
SELECTED FINANCIAL DATA
The following table contains selected financial data derived from our audited financial statements.
Year Ended December 31,
2016
2015
2014
2013 (a)
2012 (a)
(Thousands of Dollars, Except Per Unit Data)
Statement of Income Data:
Revenues (b)
Operating income (loss)
Income (loss) from continuing operations (c)
Income (loss) from continuing operations per
common unit (c)
Cash distributions per unit applicable
to common limited partners
$ 1,756,682
359,109
150,003
$ 2,084,040
390,704
305,946
$ 3,075,118
346,901
214,169
$ 3,463,732
(19,121)
(185,509)
$ 5,945,736
(18,168)
(166,001)
1.27
4.380
3.29
4.380
2.14
4.380
(2.89)
(2.79)
4.380
4.380
Balance Sheet Data:
Property, plant and equipment, net
Total assets
Long-term debt
Total partners’ equity
2016
2015
2014
2013
2012
December 31,
(Thousands of Dollars)
$ 3,722,283
5,030,545
3,014,364
1,611,617
$ 3,683,571
5,125,525
3,055,612
1,609,844
$ 3,460,732
4,918,796
2,749,452
1,716,210
$ 3,310,653
5,032,186
2,655,553
1,903,794
$ 3,238,460
5,613,089
2,124,582
2,584,995
(a)
(b)
(c)
The losses for the years ended December 31, 2013 and 2012 are mainly due to goodwill impairment and other asset impairment
charges.
The decline in revenues from 2012 to 2013 is due to reductions in our fuels marketing segment mainly resulting from the disposition
of our asphalt business. Further declines in revenues from 2013 through 2016 are mainly from a reduction in marketing activity and
lower commodity prices.
Includes the impact of a $58.7 million non-cash impairment charge on the Axeon term loan in 2016 and a $56.3 million non-cash
gain associated with the Linden terminal acquisition in 2015.
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ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following review of our results of operations and financial condition should be read in conjunction with “Cautionary
Statement Regarding Forward-Looking Information,” Items 1., 1A. and 2. “Business, Risk Factors and Properties” and Item 8.
“Financial Statements and Supplementary Data” included in this report.
OVERVIEW
NuStar Energy L.P. (NYSE: NS) is engaged in the transportation of petroleum products and anhydrous ammonia, the
terminalling and storage of petroleum products and the marketing of petroleum products. Unless otherwise indicated, the terms
“NuStar Energy,” “NS,” “the Partnership,” “we,” “our” and “us” are used in this report to refer to NuStar Energy L.P., to one or
more of our consolidated subsidiaries or to all of them taken as a whole. NuStar GP Holdings, LLC (NuStar GP Holdings or
NSH) (NYSE: NSH) owns our general partner, Riverwalk Logistics, L.P., and owns an approximate 13% common limited
partner interest in us as of December 31, 2016. Our Management’s Discussion and Analysis of Financial Condition and Results
of Operations is presented in seven sections:
• Overview
• Results of Operations
• Trends and Outlook
• Liquidity and Capital Resources
• Related Party Transactions
• Critical Accounting Policies
• New Accounting Pronouncements
Recent Developments
Martin Terminal Acquisition. On December 21, 2016, we acquired crude oil and refined product storage assets in Corpus
Christi, TX for $95.7 million, including $2.1 million of capital expenditure reimbursements, from Martin Operating Partnership
L.P. (the Martin Terminal Acquisition). The assets acquired are in our storage segment and include 900,000 barrels of crude oil
storage capacity, 250,000 barrels of refined product storage capacity and exclusive use of the Port of Corpus Christi’s new
crude oil dock. We funded the acquisition with borrowings under our revolving credit agreement. The acquired assets, which
are adjacent to our existing Corpus Christi North Beach terminal, increase our storage capacity in the Corpus Christi region and
have direct connectivity to Eagle Ford crude oil production. Additionally, we expect to benefit from our increased presence in
the Corpus Christi region, which is a strategic hub for us.
Employee Transfer from NuStar GP, LLC. On March 1, 2016, NuStar GP, LLC, the general partner of our general partner and a
wholly owned subsidiary of NuStar GP Holdings, transferred and assigned to NuStar Services Company LLC (NuStar Services
Co), a wholly owned subsidiary of NuStar Energy, all of NuStar GP, LLC’s employees and related benefit plans, programs,
contracts and policies (the Employee Transfer). As a result of the Employee Transfer, we pay employee costs directly and
sponsor the long-term incentive plan and other employee benefit plans. Please refer to the Notes to Consolidated Financial
Statements in Item 8. “Financial Statements and Supplementary Data” for the following: Note 18 for further discussion of the
Employee Transfer and our related party agreements, Note 23 for a discussion of our employee benefit plans and Note 24 for a
discussion of our long-term incentive plan.
Linden Acquisition. On January 2, 2015, we acquired full ownership of ST Linden Terminal, LLC (Linden), which owns a
refined products terminal in Linden, NJ with 4.3 million barrels of storage capacity, for $142.5 million (the Linden
Acquisition). Prior to the Linden Acquisition, Linden operated as a joint venture between us and Linden Holding Corp., with
each party owning 50%. On the acquisition date, we remeasured our existing 50% equity investment in Linden to its fair value
of $128.0 million and we recognized a gain of $56.3 million in “Other (expense) income, net” in the consolidated statements of
income for the year ended December 31, 2015. Please refer to Note 4 of the Notes to Consolidated Financial Statements in
Item 8. “Financial Statements and Supplementary Data” for further discussion of the Linden Acquisition.
Discontinued Operations. In 2014, we divested our terminals in Mobile, AL, Wilmington, NC and Dumfries, VA and our 75%
interest in our facility in Mersin, Turkey.
Axeon. On February 26, 2014, we sold our remaining 50% ownership interest in NuStar Asphalt LLC to Lindsay Goldberg
LLC, a private investment firm (the 2014 Asphalt Sale). Effective February 27, 2014, NuStar Asphalt LLC changed its name to
Axeon Specialty Products LLC (Axeon). Upon completion of the 2014 Asphalt Sale, the parties agreed to: (i) convert the
$250.0 million unsecured revolving credit facility provided by us to Axeon (the NuStar JV Facility) from a revolving credit
36
Table of Contents
agreement into a $190.0 million term loan (the Axeon Term Loan); (ii) terminate the terminal services agreements with respect
to our terminals in Rosario, NM, Catoosa, OK and Houston, TX; (iii) amend the terminal services agreements for our terminals
in Baltimore, MD and Jacksonville, FL; and (iv) transfer ownership of both the Wilmington, NC and Dumfries, VA terminals to
Axeon. In 2016, we recognized an impairment charge on the Axeon Term Loan of $58.7 million which is included in “Other
(expense) income, net” in the consolidated statements of income. Please refer to Note 8 of the Notes to Consolidated Financial
Statements in Item 8. “Financial Statements and Supplementary Data” for additional information on the Axeon Term Loan.
Operations
We conduct our operations through our subsidiaries, primarily NuStar Logistics, L.P. (NuStar Logistics) and NuStar Pipeline
Operating Partnership L.P. (NuPOP). Our operations are divided into three reportable business segments: pipeline, storage and
fuels marketing. For a more detailed description of our segments, please refer to “Segments” under Item 1. “Business.”
Pipeline. We own 3,140 miles of refined product pipelines and 1,230 miles of crude oil pipelines, as well as approximately 4.0
million barrels of storage capacity, which comprise our Central West System. In addition, we own 2,370 miles of refined
product pipelines, consisting of the East and North Pipelines, and a 2,000 mile ammonia pipeline (the Ammonia Pipeline),
which comprise our Central East System. The East and North Pipelines have storage capacity of approximately 6.7 million
barrels.
Storage. We own terminals and storage facilities in the United States, Canada, Mexico, the Netherlands, including St. Eustatius
in the Caribbean, and the United Kingdom (UK), with approximately 84.9 million barrels of storage capacity.
Fuels Marketing. Within our fuels marketing operations, we purchase crude oil and refined petroleum products for resale. The
results of operations for the fuels marketing segment depend largely on the margin between our cost and the sales prices of the
products we market. Therefore, the results of operations for this segment are more sensitive to changes in commodity prices
compared to the operations of the pipeline and storage segments. We enter into derivative contracts to attempt to mitigate the
effects of commodity price fluctuations. The derivative instruments we use consist primarily of commodity futures and swap
contracts. Not all of our derivative instruments qualify for hedge accounting treatment under U.S. generally accepted
accounting principles. In such cases, our earnings for a period may include the gain or loss related to derivative instruments
without including the offsetting effect of the hedged item, which could result in greater earnings volatility.
Factors That Affect Results of Operations
The following factors affect the results of our operations:
•
•
•
•
•
company-specific factors, such as facility integrity issues and maintenance requirements that impact the
throughput rates of our assets;
seasonal factors that affect the demand for products transported by and/or stored in our assets and the demand for
products we sell;
industry factors, such as changes in the prices of petroleum products that affect demand and operations of our
competitors;
economic factors, such as commodity price volatility that impact our fuels marketing segment; and
factors that impact the operations served by our pipeline and storage assets, such as utilization rates and
maintenance turnaround schedules of our refining company customers and drilling activity by our crude oil
production customers.
Current Market Conditions
While the price of crude oil has recovered modestly since its sharp initial decline in 2015 and subsequent historic lows during
2016, energy industry experts predict continued price volatility and do not expect significant sustained price recovery in 2017.
Increases or decreases in the price of crude oil affect various sectors of the energy industry, including our customers in crude oil
production, refining and trading, in different ways. For example, the sustained period of low prices has forced some crude oil
producers to reduce their capital spending and drilling activity and narrow their focus to assets in the most cost-advantaged
regions. However, while some refiners have benefitted from lower crude oil prices, particularly to the extent the lower
feedstock price has been coupled with higher demand for certain refined products in some regional markets, recent increases in
refined product inventory may cause some refiners to reduce their production levels.
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Table of Contents
RESULTS OF OPERATIONS
Year Ended December 31, 2016 Compared to Year Ended December 31, 2015
Financial Highlights
(Thousands of Dollars, Except Unit and Per Unit Data)
Year Ended December 31,
2016
2015
Change
Statement of Income Data:
Revenues:
Service revenues
Product sales
Total revenues
Costs and expenses:
Cost of product sales
Operating expenses
General and administrative expenses
Depreciation and amortization expense
Total costs and expenses
Operating income
Interest expense, net
Other (expense) income, net
$ 1,083,165
$ 1,114,153
$
673,517
969,887
1,756,682
2,084,040
633,653
448,367
98,817
216,736
907,574
473,031
102,521
210,210
1,397,573
1,693,336
359,109
(138,350)
(58,783)
161,976
11,973
150,003
—
390,704
(131,868)
61,822
320,658
14,712
305,946
774
150,003
$
306,720
$
(30,988)
(296,370)
(327,358)
(273,921)
(24,664)
(3,704)
6,526
(295,763)
(31,595)
(6,482)
(120,605)
(158,682)
(2,739)
(155,943)
(774)
(156,717)
1.27
—
1.27
$
$
3.29
0.01
3.30
$
$
(2.02)
(0.01)
(2.03)
Income from continuing operations before income tax expense
Income tax expense
Income from continuing operations
Income from discontinued operations, net of tax
Net income
Basic and diluted net income per common unit:
Continuing operations
Discontinued operations
Total
$
$
$
Basic weighted-average common units outstanding
78,080,484
77,886,078
194,406
Annual Overview
Net income decreased $156.7 million for the year ended December 31, 2016, compared to the year ended December 31, 2015,
primarily due to a $58.7 million impairment charge on the Axeon Term Loan in 2016 and a $56.3 million gain associated with
the Linden Acquisition in 2015. In addition, segment operating income decreased $35.3 million, resulting mainly from
reductions in operating income for the pipeline and fuels marketing segments.
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Table of Contents
Segment Operating Highlights
(Thousands of Dollars, Except Barrel/Day Information)
Year Ended December 31,
2016
2015
Change
535,946
392,181
928,127
485,650
147,858
89,554
248,238
789,065
117,586
492,456
610,042
276,578
118,663
214,801
681,934
645,355
36,579
33,173
3,406
$
$
$
$
$
$
522,146
471,632
993,778
508,522
153,222
84,951
270,349
899,606
130,127
494,781
624,908
290,322
116,768
217,818
13,800
(79,451)
(65,651)
(22,872)
(5,364)
4,603
(22,111)
(110,541)
(12,541)
(2,325)
(14,866)
(13,744)
1,895
(3,017)
$
$
$
$
976,216
922,906
53,310
39,803
13,507
$ (294,282)
(277,551)
(16,731)
(6,630)
(10,101)
$
(20,944) $
(11,702)
(9,242)
— $
(25,606) $
(15,332)
(10,316)
42
$
4,662
3,630
1,074
(42)
$
$
$
$
$
$
$
$
$ 1,756,682
633,653
448,367
208,217
466,445
98,817
8,519
359,109
$
$ 2,084,040
907,574
473,031
201,719
501,716
102,521
8,491
390,704
$
$ (327,358)
(273,921)
(24,664)
6,498
(35,271)
(3,704)
28
(31,595)
$
Pipeline:
Refined products pipelines throughput (barrels/day)
Crude oil pipelines throughput (barrels/day)
Total throughput (barrels/day)
Throughput revenues
Operating expenses
Depreciation and amortization expense
Segment operating income
Storage:
Throughput (barrels/day)
Throughput terminal revenues
Storage terminal revenues
Total revenues
Operating expenses
Depreciation and amortization expense
Segment operating income
Fuels Marketing:
Product sales and other revenue
Cost of product sales
Gross margin
Operating expenses
Segment operating income
Consolidation and Intersegment Eliminations:
Revenues
Cost of product sales
Operating expenses
Total
Consolidated Information:
Revenues
Cost of product sales
Operating expenses
Depreciation and amortization expense
Segment operating income
General and administrative expenses
Other depreciation and amortization expense
Consolidated operating income
39
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Pipeline
Total revenues decreased $22.9 million and total throughputs decreased 65,651 barrels per day for the year ended December 31,
2016, compared to the year ended December 31, 2015, primarily due to:
•
•
•
a decrease in revenues of $36.3 million and a decrease in throughputs of 81,779 barrels per day on our Eagle Ford
System due to reduced production resulting from a sustained low crude oil price environment;
a decrease in revenues of $7.1 million and a decrease in throughputs of 6,586 barrels per day on our Ammonia
Pipeline partly due to a shipper’s facility reconfiguration, resulting in fewer barrels available for transportation,
and maintenance downtime on a portion of the pipeline; and
a decrease in revenues of $3.9 million and a decrease in throughputs of 1,551 barrels per day on our Ardmore
System due to operational issues and a turnaround at the Ardmore refinery in 2016, as well as increased short-haul
deliveries resulting in lower average tariffs.
Those decreases in pipeline revenues and throughputs were partially offset by:
•
•
•
an increase in revenues of $12.1 million and an increase in throughputs of 14,803 barrels per day on our McKee
and Three Rivers System pipelines due to higher demand in those markets, increased production at the McKee
refinery and increased volumes on pipelines with higher average tariffs;
an increase in revenues of $9.6 million and an increase in throughputs of 11,441 barrels per day on our East
Pipeline mainly due to the completion of various expansion projects beginning in the fourth quarter of 2015,
unfavorable pricing differentials in 2015 in markets served by the East Pipeline and lower throughput in 2015 due
to maintenance downtime on a portion of the pipeline; and
an increase in revenues of $3.4 million and an increase in throughputs of 1,392 barrels per day on our North
Pipeline due to increased refinery production shipped via pipeline and increased long-haul deliveries resulting in
higher average tariffs.
Operating expenses decreased $5.4 million for the year ended December 31, 2016, compared to the year ended December 31,
2015, primarily due to lower operating expenses of $8.7 million on our Eagle Ford System, consistent with the decrease in
throughputs. The decrease in pipeline operating expenses was partially offset by higher maintenance and regulatory expenses of
$3.2 million, mainly on our Central West Refined Products Pipelines.
Depreciation and amortization expense increased $4.6 million for the year ended December 31, 2016, compared to the year
ended December 31, 2015, mainly due to the completion of pipeline projects.
Storage
Throughput terminal revenues decreased $12.5 million and throughputs decreased 110,541 barrels per day for the year ended
December 31, 2016, compared to the year ended December 31, 2015, primarily due to:
•
•
a decrease in revenues of $10.9 million and a decrease in throughputs of 82,177 barrels per day at our Corpus
Christi North Beach terminal due to (i) a decrease in Eagle Ford Shale crude oil being shipped to Corpus Christi,
consistent with the decrease in pipeline throughputs and (ii) the completion of a pipeline expansion project in the
first quarter of 2016, in which we transport volumes from North Beach to our customer’s refineries, thus reducing
volumes moved over our docks; and
a decrease in revenues of $3.3 million and a decrease in throughputs of 35,497 barrels per day due to turnarounds
at the refineries served by our Benicia and Corpus Christi crude oil storage tank facilities, as well as operational
issues at a customer’s Corpus Christi refinery in 2016.
The decreases were partially offset by an increase in revenue of $3.0 million and an increase in throughputs of 9,044 barrels per
day at our McKee and Three Rivers System terminals due to higher demand in those markets, as well as increased production at
the McKee refinery.
Storage terminal revenues decreased $2.3 million for the year ended December 31, 2016, compared to the year ended
December 31, 2015. Revenues from our international terminals decreased $17.7 million primarily due to a decrease in revenues
at our St. Eustatius terminal of $8.3 million, resulting mainly from lower throughput and related handling fees, as well as a
decrease in revenues of $5.9 million at our UK terminal facilities, mainly due to fluctuations in foreign exchange rates. These
decreases were partially offset by an increase of $15.3 million in domestic revenues. Domestic revenues increased $10.1
million from rate escalations and new customer contracts mainly at our Selby, CA, Linden, NJ, Blue Island, IL and Piney Point,
MD terminals. In addition, revenues at our St. James, LA terminal increased $3.1 million due to completed terminal expansion
projects.
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Table of Contents
Operating expenses decreased $13.7 million for the year ended December 31, 2016, compared to the year ended December 31,
2015, primarily due to:
•
•
•
a decrease of $11.8 million in operating expenses at our international terminals, mainly at our St. Eustatius
terminal facility due to higher property taxes in 2015, and lower employee related costs and reimbursable
expenses in 2016;
a decrease of $3.1 million resulting from an insurance settlement for environmental remediation expenses
incurred on a previously sold terminal; and
a decrease of $2.0 million resulting from lower wharfage and dockage costs at our Corpus Christi North Beach
terminal.
The decreases in storage operating expenses were partially offset by a $3.9 million increase in regulatory and maintenance
expenses mainly at our Central West terminal facilities and $1.6 million in cancelled capital project costs.
Fuels Marketing
Segment operating income decreased $10.1 million for the year ended December 31, 2016, compared to the year ended
December 31, 2015, primarily due to a decrease in gross margin of $7.9 million and $6.6 million from our fuel oil trading and
bunker fuel operations, respectively. The lower gross margins were partially offset by a reduction in operating expenses of $6.6
million mainly from our bunker fuel operations due to lower bad debt expense and decreased product inspection and marine
vessel costs.
Consolidation and Intersegment Eliminations
Revenue and operating expense eliminations primarily relate to storage fees charged to the fuels marketing segment by the
storage segment. Cost of product sales eliminations represent expenses charged to the fuels marketing segment for costs
associated with inventory that are expensed once the inventory is sold.
General
General and administrative expenses decreased $3.7 million for the year ended December 31, 2016, compared to the year ended
December 31, 2015, primarily due to a decrease in employee benefit costs which was partially offset by increased
compensation expense associated with our long-term incentive plan.
Interest expense, net increased $6.5 million for the year ended December 31, 2016, compared to the year ended December 31,
2015, primarily due to increased interest costs associated with higher borrowings under our revolving credit agreement, as well
as lower capitalized interest resulting from fewer capital projects.
For the year ended December 31, 2016, we recorded other expense, net of $58.8 million mainly due to an impairment charge of
$58.7 million recognized on the Axeon Term Loan. For the year ended December 31, 2015, we recorded other income, net of
$61.8 million mainly due to the $56.3 million gain associated with the Linden Acquisition.
Income tax expense decreased $2.7 million for the year ended December 31, 2016, compared to the year ended December 31,
2015, primarily due to lower margin tax in Texas, a decrease in the UK tax rate and a reduction in our St. Eustatius and Canada
withholding tax. Please refer to Note 25 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and
Supplementary Data” for a discussion on income taxes.
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Table of Contents
Year Ended December 31, 2015 Compared to Year Ended December 31, 2014
Financial Highlights
(Thousands of Dollars, Except Unit and Per Unit Data)
Statement of Income Data:
Revenues:
Service revenues
Product sales
Total revenues
Costs and expenses:
Cost of product sales
Operating expenses
General and administrative expenses
Depreciation and amortization expense
Total costs and expenses
Operating income
Equity in earnings of joint ventures
Interest expense, net
Interest income from related party
Other income, net
Year Ended December 31,
2015
2014
Change
$ 1,114,153
$ 1,026,446
$
969,887
2,084,040
2,048,672
3,075,118
87,707
(1,078,785)
(991,078)
907,574
473,031
102,521
210,210
1,693,336
390,704
—
(131,868)
—
61,822
320,658
14,712
305,946
774
306,720
$
1,967,528
472,925
96,056
191,708
2,728,217
(1,059,954)
106
6,465
18,502
(1,034,881)
346,901
4,796
(132,281)
1,055
4,499
224,970
10,801
214,169
(3,791)
210,378
43,803
(4,796)
413
(1,055)
57,323
95,688
3,911
91,777
4,565
96,342
1.15
0.05
1.20
—
$
$
$
3.29
0.01
3.30
$
$
2.14
(0.04)
2.10
Income from continuing operations before income tax expense
Income tax expense
Income from continuing operations
Income (loss) from discontinued operations, net of tax
Net income
Basic and diluted net income (loss) per common unit:
Continuing operations
Discontinued operations
Total
$
$
$
Basic weighted-average common units outstanding
77,886,078
77,886,078
Annual Overview
Net income increased $96.3 million for the year ended December 31, 2015, compared to the year ended December 31, 2014,
primarily due to an increase of $48.6 million in segment operating income, resulting mainly from improvements in the pipeline
and storage segments, and a $56.3 million gain associated with the Linden Acquisition.
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Segment Operating Highlights
(Thousands of Dollars, Except Barrel/Day Information)
Year Ended December 31,
2015
2014
Change
522,146
471,632
993,778
508,522
153,222
84,951
270,349
899,606
130,127
494,781
624,908
290,322
116,768
217,818
$
$
$
$
510,737
437,757
948,494
477,030
154,106
77,691
245,233
887,607
123,051
441,455
564,506
277,554
103,848
183,104
$
$
$
$
11,409
33,875
45,284
31,492
(884)
7,260
25,116
11,999
7,076
53,326
60,402
12,768
12,920
34,714
976,216
922,906
53,310
39,803
—
13,507
$ 2,060,017
1,983,339
76,678
51,857
16
24,805
$
$ (1,083,801)
(1,060,433)
(23,368)
(12,054)
(16)
(11,298)
$
(25,606) $
(15,332)
(10,316)
42
$
(26,435) $
(15,811)
(10,592)
(32) $
829
479
276
74
$
$
$
$
$
$
$
$
$ 2,084,040
907,574
473,031
201,719
501,716
102,521
8,491
390,704
$
$ 3,075,118
1,967,528
472,925
181,555
453,110
96,056
10,153
346,901
$
$
$
(991,078)
(1,059,954)
106
20,164
48,606
6,465
(1,662)
43,803
Pipeline:
Refined products pipelines throughput (barrels/day)
Crude oil pipelines throughput (barrels/day)
Total throughput (barrels/day)
Throughput revenues
Operating expenses
Depreciation and amortization expense
Segment operating income
Storage:
Throughput (barrels/day)
Throughput terminal revenues
Storage terminal revenues
Total revenues
Operating expenses
Depreciation and amortization expense
Segment operating income
Fuels Marketing:
Product sales and other revenue
Cost of product sales
Gross margin
Operating expenses
Depreciation and amortization expense
Segment operating income
Consolidation and Intersegment Eliminations:
Revenues
Cost of product sales
Operating expenses
Total
Consolidated Information:
Revenues
Cost of product sales
Operating expenses
Depreciation and amortization expense
Segment operating income
General and administrative expenses
Other depreciation and amortization expense
Consolidated operating income
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Pipeline
Revenues increased $31.5 million and throughputs increased 45,284 barrels per day for the year ended December 31, 2015,
compared to the year ended December 31, 2014, primarily due to:
•
•
•
an increase in revenues of $17.0 million and an increase in throughputs of 34,564 barrels per day on our Eagle
Ford System, primarily resulting from completion of expansion projects that increased our overall capacity;
an increase in revenues of $11.9 million and an increase in throughputs of 11,676 barrels per day as a result of
increased production in 2015 and a turnaround during the first quarter of 2014 at the refinery served by our
McKee System; and
an increase in revenues of $3.6 million, despite throughputs that remained flat, on our Ammonia Pipeline as a
result of increased long-haul deliveries and the annual index adjustment in July 2015.
The increases in pipeline revenues and throughputs were partially offset by a decrease in revenues of $4.4 million and a
decrease in throughputs of 2,811 barrels per day due to turnarounds at refineries served by the East Pipeline and unfavorable
pricing differentials in markets served by the East Pipeline.
Operating expenses decreased $0.9 million, despite an increase in throughputs, for the year ended December 31, 2015,
compared to the year ended December 31, 2014, primarily due to the completion of a capital project to install permanent power
along our South Texas Crude System, reducing power and rental costs.
Depreciation and amortization expense increased $7.3 million for the year ended December 31, 2015, compared to the year
ended December 31, 2014, mainly due to the completion of expansion projects.
Storage
Throughput terminal revenues increased $7.1 million and throughputs increased 11,999 barrels per day for the year ended
December 31, 2015, compared to the year ended December 31, 2014, primarily due to:
•
•
•
an increase in revenues of $2.5 million and an increase in throughputs of 19,853 barrels per day at our Corpus
Christi North Beach terminal due to an increase in Eagle Ford Shale crude oil being shipped to Corpus Christi and
the completion of related expansion projects;
an increase in revenues of $2.3 million and an increase in throughputs of 6,263 barrels per day at our terminals in
Edinburg, Harlingen and Paulsboro, mainly due to increased demand; and
an increase in revenues of $2.0 million and an increase in throughputs of 12,558 barrels per day as a result of a
turnaround during the first quarter of 2014 at the refinery served by our Benicia crude oil refinery tanks.
The increases in storage throughput terminal revenues and throughputs were partially offset by a decrease in revenues of $0.9
million and a decrease in throughputs of 21,107 barrels per day as a result of a turnaround during the first quarter of 2015 at the
refinery served by our Texas City crude oil refinery tanks.
Storage terminal revenues increased $53.3 million for the year ended December 31, 2015, compared to the year ended
December 31, 2014, primarily due to:
•
•
•
•
an increase of $41.5 million as a result of the Linden Acquisition;
an increase of $11.8 million at our domestic terminal facilities, mainly due to storage rate escalations and new
customers at our Texas City, West Coast and Asphalt Terminals;
an increase of $9.9 million at our St. Eustatius terminal facility, mainly due to higher demand for storage and
increased throughput and related handling fees; and
an increase of $5.0 million at our Point Tupper terminal facility, due to new customers and rate escalations, as
well as increased throughput and related handling fees.
The increases in storage terminal revenues were partially offset by:
•
•
a decrease of $8.4 million at our Amsterdam terminal facility, primarily due to the effect of foreign exchange
rates; and
a decrease of $3.5 million at our St. James terminal facility, mainly due to reduced volumes delivered to one of
our unit train offloading facilities, partially offset by increased revenues from storage rate escalations.
Operating expenses increased $12.8 million for the year ended December 31, 2015, compared to the year ended December 31,
2014, primarily due to:
•
•
an increase of $12.6 million as a result of the Linden Acquisition; and
an increase of $4.6 million in regulatory and maintenance expenses, mainly at our St. James and St. Eustatius
terminal facilities.
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The increases in storage operating expenses were partially offset by a decrease of $3.4 million in contract services costs, mainly
at our St. James terminal facility due to a reduction in dock and rail labor costs.
Depreciation and amortization expense increased $12.9 million for the year ended December 31, 2015, compared to the year
ended December 31, 2014, mainly due to the assets associated with the Linden Acquisition.
Fuels Marketing
Segment operating income decreased $11.3 million for the year ended December 31, 2015, compared to the year ended
December 31, 2014, primarily due to lower gross margins from our bunker fuel operations and refined product sales. The lower
gross margins were partially offset by a reduction in operating expenses due to decreased marine vessel costs and lower bad
debt expense in 2015.
Consolidation and Intersegment Eliminations
Revenue and operating expense eliminations primarily relate to storage fees charged to the fuels marketing segment by the
storage segment. Cost of product sales eliminations represent expenses charged to the fuels marketing segment for costs
associated with inventory that are expensed once the inventory is sold.
General
General and administrative expenses increased $6.5 million for the year ended December 31, 2015, compared to the year ended
December 31, 2014, primarily due to:
•
•
•
a $3.6 million increase in outside legal and other professional fees;
a $3.5 million increase in salaries and wages mainly due to increased headcount and higher employee benefit
costs; and
a $3.1 million increase as a result of the termination of a services agreement between Axeon and NuStar GP, LLC
in June 2014, under which Axeon reimbursed us for certain corporate support services.
The increases in general and administrative expenses were partially offset by a decrease of $4.5 million in compensation
expense associated with our long-term incentive plans, which fluctuated with our common unit price.
Equity in earnings of joint ventures for the year ended December 31, 2014 primarily related to our equity investment in Linden
prior to the Linden Acquisition.
Interest expense, net decreased $0.4 million for the year ended December 31, 2015, compared to the year ended December 31,
2014, mainly due to increased interest income from the Axeon Term Loan. The decrease in interest expense, net was partially
offset by increased interest costs associated with higher borrowings under our revolving credit agreement.
Other income, net increased by $57.3 million for the year ended December 31, 2015, compared to the year ended December 31,
2014, mainly due to the $56.3 million gain associated with the Linden Acquisition.
Income tax expense increased $3.9 million for the year ended December 31, 2015, compared to the year ended December 31,
2014, mainly due to estimated withholding taxes on our planned repatriation of cash held by foreign subsidiaries in 2016.
Please refer to Note 25 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary
Data” for a discussion on income taxes.
For the year ended December 31, 2015, we recorded income from discontinued operations of $0.8 million, compared to a loss
from discontinued operations of $3.8 million for the year ended December 31, 2014. Discontinued operations include the
results of operations of certain storage assets that were divested in 2014 and the first quarter of 2015.
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TRENDS AND OUTLOOK
We believe that the fact that we provide both storage and pipeline services, for crude and refined products, to customers in
sectors across the energy industry, throughout the country and around the world, offers some insulation from the impact of
market fluctuations on our results of operations. Since high crude oil prices have tended to benefit our producer customers, high
prices have also correlated with increased demand for our crude oil pipeline services. On the other hand, depressed crude oil
prices, when coupled with an industry expectation of higher prices in the future, or a contango market, has historically
correlated with increased demand from trading companies for our storage services.
Because of the geographic diversity of our assets, our results of operations are not dependent on the regions or markets that
have been hardest hit by depressed crude oil prices, the domestic shale play regions, which was demonstrated by the fact that,
in 2016, revenue from our Eagle Ford pipeline and storage assets constituted only 12% of our total pipeline and storage
segment revenue. Although our assets in the Eagle Ford region have experienced lower throughputs as production has slowed,
the fact that we have minimum volume throughput contracts with large, creditworthy customers has minimized the negative
impact of that slowdown on our results of operations.
In addition to the diversity of our customers, our assets, the services we offer and the markets we serve, we believe our
contracts, many of which are long-term, take-or-pay arrangements for committed storage or throughput capacity, also help to
blunt the impact of volatility of crude oil prices on our results of operations. In the locations at which our assets are integrated
physically with the refineries the assets serve, we believe the results generated by those assets depend to a greater degree on the
refinery’s continuing need to receive, store and transport the crude and refined products than on crude or refined product prices.
For 2017, we expect consistent volumes in our pipeline segment as any declines in crude oil pipelines are expected to be offset
by higher volumes on our refined product pipelines. We are forecasting near minimum take-or-pay volumes on our South Texas
Crude System, allowing for possible upside if production in the Eagle Ford region ramps up. We expect our storage segment to
benefit in 2017 from favorable storage contract renewals and the Martin Terminal Acquisition. Earnings in our fuels marketing
segment, as in any margin-based business, are subject to many factors that can increase or reduce margins, which may cause the
segment’s actual results to vary significantly from our forecast.
Our outlook for the partnership, both overall and for any of our segments, may change, as we base our expectations on our
continuing evaluation of a number of factors, many of which are outside our control. These factors include, but are not limited
to, the state of the economy and the capital markets, changes to our customers’ refinery maintenance schedules and unplanned
refinery downtime, supply of and demand for crude oil, refined products and anhydrous ammonia, demand for our
transportation and storage services and changes in laws or regulations affecting our assets.
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LIQUIDITY AND CAPITAL RESOURCES
Overview
Primary Cash Requirements. Our primary cash requirements are for distributions to our partners, capital expenditures, debt
service and operating expenses.
Our partnership agreement requires that we distribute all “Available Cash” to our common limited partners and general partner
each quarter, and this term is defined in the partnership agreement generally as cash on hand at the end of the quarter, plus
certain permitted borrowings made subsequent to the end of the quarter, less cash reserves determined by our board of
directors.
Sources of Funds. Each year, our objective is to fund our total annual reliability capital expenditures and distribution
requirements with our net cash provided by operating activities during that year. If we do not generate sufficient cash from
operations to meet that objective, we utilize cash on hand or other sources of cash flow, which in the past have primarily
included borrowings under our revolving credit agreement, sales of non-strategic assets and, to the extent necessary, funds
raised through equity or debt offerings under our shelf registration statements. We have typically funded our strategic capital
expenditures and acquisitions from external sources, primarily borrowings under our revolving credit agreement or funds raised
through equity or debt offerings. However, our ability to raise funds by issuing debt or equity depends on many factors beyond
our control. Our risk factors in Item 1A. “Risk Factors” describe the risks inherent to these sources of funding and the
availability thereof.
During periods when our cash flow from operations is less than our distribution and reliability capital requirements, we may
maintain our distribution level because we can use other sources of Available Cash, as provided in our partnership agreement,
including borrowings under our revolving credit agreement and proceeds from the sales of assets. Our risk factors in Item 1A.
“Risk Factors” describe the risks inherent in our ability to maintain or grow our distribution.
For the years ended December 31, 2016, 2015 and 2014, our cash flow from operations exceeded our distributions to our
partners and our reliability capital expenditures. For 2017, we currently expect to generate cash from operations in excess of
our distribution and reliability capital requirements.
Cash Flows for the Years Ended December 31, 2016, 2015 and 2014
The following table summarizes our cash flows from operating, investing and financing activities:
Net cash provided by (used in):
Operating activities
Investing activities
Financing activities
Effect of foreign exchange rate changes on cash
Net (decrease) increase in cash and cash equivalents
Year Ended December 31,
2016
2015
2014
(Thousands of Dollars)
$
$
$
436,761
(311,078)
(211,324)
2,721
(82,920) $
524,937
(452,029)
(29,229)
(12,729)
30,950
$
$
518,523
(340,231)
(188,185)
(2,938)
(12,831)
Net cash provided by operating activities the year ended December 31, 2016 was $436.8 million, compared to $524.9 million
the year ended December 31, 2015, primarily due to lower net income in 2016. In addition, our working capital decreased by
$3.7 million for the year ended December 31, 2016, compared to a decrease of $50.6 million for the year ended December 31,
2015. Please refer to the Working Capital Requirements section below for a discussion of the changes in working capital.
For the year ended December 31, 2016, net cash provided by operating activities primarily was used to fund our distributions to
unitholders and our general partner in the aggregate amount of $393.0 million and reliability capital expenditures of $38.2
million. The proceeds from debt borrowings, net of repayments, proceeds from the issuance of common and preferred units and
cash on hand were used to fund our strategic capital expenditures, including the Martin Terminal Acquisition.
For the year ended December 31, 2015, the majority of net cash provided by operating activities was used to fund our
distributions to unitholders and our general partner in the aggregate amount of $392.2 million and to fund $40.0 million of
reliability capital expenditures. The proceeds from debt borrowings, net of repayments, combined with a portion of net cash
provided by operating activities, were used to fund our strategic capital expenditures, including the Linden Acquisition.
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For the year ended December 31, 2014, the majority of net cash provided by operating activities was used to fund our
distributions to unitholders and our general partner in the aggregate amount of $392.2 million and to fund $28.6 million of
reliability capital expenditures. The proceeds from debt borrowings, net of repayments, combined with net cash provided by
operating activities and proceeds from the sales of assets, were used to fund our strategic capital expenditures primarily related
to our pipeline and storage segments and advances to Axeon under the NuStar JV Facility.
Revolving Credit Agreement
NuStar Logistics is a party to a $1.5 billion five-year revolving credit agreement (the Revolving Credit Agreement), which
matures on October 29, 2019. The Revolving Credit Agreement includes an option allowing NuStar Logistics to request an
aggregate increase in the commitments from the lenders of up to $250.0 million (after which increase the aggregate
commitment from all lenders shall not exceed $1.75 billion). The Revolving Credit Agreement also includes the ability to
borrow up to the equivalent of $250.0 million in Euros and up to the equivalent of $250.0 million in British Pounds Sterling.
Obligations under the Revolving Credit Agreement are guaranteed by NuStar Energy and NuPOP.
The Revolving Credit Agreement contains customary restrictive covenants, such as limitations on indebtedness, liens, mergers,
asset transfers and certain investing activities. In addition, the Revolving Credit Agreement requires us to maintain, as of the
end of each rolling period of four consecutive fiscal quarters, a consolidated debt coverage ratio (consolidated debt to
consolidated EBITDA, each as defined in the Revolving Credit Agreement) not to exceed 5.00-to-1.00. If we consummate an
acquisition for an aggregate net consideration of at least $50.0 million, the maximum consolidated debt coverage ratio will
increase to 5.50-to-1.00 for two rolling periods. As of December 31, 2016, our consolidated debt coverage ratio could not
exceed 5.50-to-1.00, as a result of the Martin Terminal Acquisition in December 2016. The requirement not to exceed a
maximum consolidated debt coverage ratio may limit the amount we can borrow under the Revolving Credit Agreement to an
amount less than the total amount available for borrowing. As of December 31, 2016, our consolidated debt coverage ratio was
4.3x, and we had $645.2 million available for borrowing.
Letters of credit issued under our Revolving Credit Agreement totaled $15.8 million as of December 31, 2016. Letters of credit
are limited to $750.0 million (including up to the equivalent of $25.0 million in Euros and up to the equivalent of $25.0 million
in British Pounds Sterling) and also restrict the amount we can borrow under the Revolving Credit Agreement.
Please refer to Note 13 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary
Data” for a discussion of our debt agreements.
Other Sources of Liquidity
Other sources of liquidity consist of the following:
•
•
•
$365.4 million in revenue bonds pursuant to the Gulf Opportunity Zone Act of 2005 (the GoZone Bonds), with $42.4
million remaining in the trust as of December 31, 2016, supported by $370.2 million in letters of credit;
a $125.0 million receivables financing agreement between NuStar Energy, NuStar Finance LLC and third-party
lenders (the Receivables Financing Agreement), with the amount available for borrowing based on the availability of
eligible receivables and other customary factors and conditions; and
two short-term line of credit agreements with an aggregate uncommitted borrowing capacity of up to $75.0 million,
with $54.0 million of borrowings outstanding as of December 31, 2016.
Please refer to Note 13 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary
Data” for a more detailed discussion of these debt agreements.
LOC Agreement
NuStar Logistics is a party to a $100.0 million uncommitted letter of credit agreement, which provides for standby letters of
credit or guarantees with a term of up to one year (LOC Agreement). Any letters of credit issued under the LOC Agreement do
not reduce availability under the Revolving Credit Agreement. As of December 31, 2016, letters of credit issued under the LOC
Agreement totaled $9.0 million.
Issuance of Units
In the fourth quarter of 2016, we issued 9,060,000 of our 8.50% Series A Fixed-to-Floating Rate Cumulative Redeemable
Perpetual Preferred Units (the Preferred Units) representing limited partner interests at a price of $25.00 per unit. We used the
net proceeds of $218.4 million from this issuance for general partnership purposes, including the funding of capital
expenditures and repayments of outstanding borrowings under the Revolving Credit Agreement.
During the year ended December 31, 2016, we issued 595,050 common units representing limited partner interests at an
average price of $47.39 per unit for proceeds of $28.3 million, net of $0.5 million of issuance costs. We used these proceeds,
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which includes a contribution of $0.6 million from our general partner to maintain its 2% general partner interest, for general
partnership purposes, including repayments of outstanding borrowings under the Revolving Credit Agreement.
Please refer to Note 20 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary
Data” for additional information on these issuances.
Repatriation
Previously, all undistributed earnings of our foreign subsidiaries were indefinitely reinvested. In 2016, we began to repatriate a
portion of undistributed foreign earnings in order to provide greater flexibility to meet cash flow needs. During the year ended
December 31, 2016, we repatriated $110.8 million of cash from our foreign subsidiaries. For 2017, we will continue to evaluate
our cash flow needs and may repatriate funds from our foreign subsidiaries as a source of liquidity.
Capital Requirements
Our operations require significant investments to maintain, upgrade or enhance the operating capacity of our existing assets.
Our capital expenditures consist of:
•
•
strategic capital expenditures, such as those to expand or upgrade the operating capacity, increase efficiency or
increase the earnings potential of existing assets, whether through construction or acquisition, as well as certain capital
expenditures related to support functions; and
reliability capital expenditures, such as those required to maintain the existing operating capacity of existing assets or
extend their useful lives, as well as those required to maintain equipment reliability and safety.
The following table summarizes our capital expenditures, and the amount we expect to spend for 2017:
Strategic Capital
Expenditures (a)
Reliability Capital
Expenditures (b)
Total
For the year ended December 31:
2016
2015
2014
$
$
$
261,860
430,870
328,330
$
$
$
38,155
40,002
28,635
$
$
$
300,015
470,872
356,965
Expected for the year ended December 31, 2017
$ 440,000 - 460,000
$ 35,000 - 55,000
$ 475,000 - 515,000
(a) Strategic capital expenditures mainly include projects associated with the conversion and expansion of existing assets. Strategic
capital also includes $95.7 million for the Martin Terminal Acquisition in 2016 and $142.5 million for the Linden Acquisition in
2015. In 2015 and 2014, strategic capital also includes the reactivation and conversion of our 200-mile pipeline between Mont
Belvieu and Corpus Christi, Texas.
(b) Reliability capital expenditures primarily relate to maintenance upgrade projects at our terminals.
We continue to evaluate our capital budget and make changes as economic conditions warrant, and our actual capital
expenditures for 2017 may increase or decrease from the budgeted amounts. We believe cash on hand, combined with the
sources of liquidity previously described, will be sufficient to fund our capital expenditures in 2017, and our internal growth
projects can be accelerated or scaled back depending on market conditions or customer demand.
Working Capital Requirements
Working capital requirements, particularly in our fuels marketing segment, may vary with the seasonality of demand and the
volatility of commodity prices for the products we market. This seasonality in demand and the volatility of commodity prices
affect our accounts receivable and accounts payable balances, which vary depending on timing of payments.
During the year ended December 31, 2016, accounts receivable increased $23.2 million and accounts payable increased $14.1
million primarily due to the timing of payments related to our bunker fuel operations and crude oil trading activity.
During the year ended December 31, 2015, inventories decreased $16.8 million mainly due to the continued decline in crude oil
prices. In addition, inventory volumes decreased in 2015 primarily due to decreased bunker fuel operations activity. During the
year ended December 31, 2015, accounts receivable decreased $67.3 million and accounts payable decreased $32.2 million
primarily due to decreased bunker fuel operations and crude oil trading activity.
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During the year ended December 31, 2014, inventories decreased $82.1 million primarily due to a steep decline in crude oil
market price during the fourth quarter of 2014. We also reduced the volume of our inventory carried in our bunker fuel
operations and our heavy fuel oil trading operations. During the year ended December 31, 2014, accounts receivable decreased
$72.3 million and accounts payable decreased $153.7 million mainly due to the bunker fuel supply strategy and less crude oil
trading activity. In addition, the termination of the crude oil supply agreement with Axeon on January 1, 2014 caused a
decrease in both accounts payable and the receivable from related parties.
Axeon Term Loan and Credit Support
In December 2016, Lindsay Goldberg LLC informed us that they entered into an agreement to sell Axeon’s retail asphalt sales
and distribution business (the Axeon Sale), and we entered into an agreement with Axeon (the Axeon Letter Agreement) to settle
and terminate the Axeon Term Loan with a $110.0 million payment to us upon closing of the Axeon Sale. As a result of the
Axeon Letter Agreement and our review of Axeon’s financial statements, we determined it was probable that we would not
receive all contractual amounts due under the Axeon Term Loan. Therefore, we recorded a charge of $58.7 million, included in
“Other (expense) income, net” in the consolidated statements of income, to reduce the carrying amount of the Axeon Term Loan
to $110.0 million and reclassified the Axeon Term Loan from “Other long-term assets, net” to “Other current assets” on the
consolidated balance sheet as of December 31, 2016. The Axeon Sale closed on February 22, 2017. In conjunction with the
closing, we received the $110.0 million payment in accordance with the Axeon Letter Agreement, the Axeon Term Loan terminated
and we are no longer required to provide ongoing credit support to Axeon. We were not obligated to perform under any of the
guarantees or letters of credit provided prior to the closing of the Axeon Sale. We are in the process of terminating certain
guarantees that we previously issued on Axeon’s behalf that remain outstanding after the Axeon Sale, but these guarantees are
supported by a letter of credit provided to us in an amount equal to those remaining guarantees, thereby reducing our exposure
to zero. In addition, in connection with the closing of the Axeon Sale, the terminal storage agreements that Axeon has with our
Jacksonville, Florida and Baltimore, Maryland terminal facilities were amended to increase the storage fees.
The recently terminated Axeon Term Loan included scheduled repayments to reduce the outstanding amount from $190.0
million to $175.0 million as of December 31, 2014 and then to $150.0 million on September 30, 2015. Any repayments of the
Axeon Term Loan were subject to Axeon meeting certain restrictive requirements contained in its third-party asset-based
revolving credit facility. In 2015 and 2014, those requirements prohibited Axeon from making the two scheduled principal
payments, which, under the provisions of the Axeon Term Loan, increased the interest rate payable by Axeon. The Axeon Term
Loan bore interest based on either an alternative base rate or a LIBOR-based rate and was scheduled to be repaid no later than
September 28, 2019. We recognized interest income over the term of the loan in “Interest expense, net” on the consolidated
statements of income. During the year ended December 31, 2016, the weighted average interest rate was 5.7%.
We also were obligated to provide credit support, such as guarantees, letters of credit and cash collateral, as applicable, of up to
$125.0 million to Axeon. As of December 31, 2016, we had provided guarantees for Axeon with an aggregate maximum
potential exposure of $54.1 million, plus one guarantee to suppliers that did not specify a maximum amount. As of
December 31, 2016, we had also provided $16.7 million in letters of credit on behalf of Axeon.
Defined Benefit Plans Funding
During 2016, we contributed $15.8 million to our pension and postretirement benefit plans. We expect to contribute
approximately $11.5 million to our pension and postretirement benefit plans in 2017, which principally represents contributions
either required by regulations or laws or, with respect to unfunded plans, necessary to fund current benefits. Pension and
postretirement benefit plans funding beyond 2017 is uncertain as the funding varies from year to year based upon changes in
the fair value of the plan assets and actuarial assumptions.
Distributions
NuStar Energy’s partnership agreement, as amended, determines the amount and priority of cash distributions that our
unitholders and general partner may receive. The general partner receives a 2% distribution with respect to its general partner
interest. The general partner is also entitled to incentive distributions if the amount we distribute with respect to any quarter
exceeds $0.60 per unit. For a detailed discussion of the incentive distribution targets, please read Item 5. “Market for
Registrant’s Common Units, Related Unitholder Matters and Issuer Purchases of Equity Securities.”
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The following table reflects the allocation of total cash distributions to the general and common limited partners applicable to
the period in which the distributions were earned:
General partner interest
General partner incentive distribution
Total general partner distribution
Common limited partners’ distribution
Total cash distributions
Cash distributions per unit applicable to common limited partners
Year Ended December 31,
2016
2015
2014
(Thousands of Dollars, Except Per Unit Data)
$
$
$
7,877
$
7,844
$
43,407
51,284
342,598
393,882
4.380
$
$
43,220
51,064
341,140
392,204
4.380
$
$
7,844
43,220
51,064
341,140
392,204
4.380
Actual distribution payments to our general and common limited partners are made within 45 days after the end of each quarter
as of a record date that is set after the end of each quarter. The following table summarizes information related to our quarterly
cash distributions to our general and common limited partners:
Quarter Ended
December 31, 2016 (a)
September 30, 2016
June 30, 2016
March 31, 2016
Cash
Distributions
Per Unit
Total Cash
Distributions
(Thousands of Dollars)
Record Date
Payment Date
$
$
$
$
1.095
1.095
1.095
1.095
$
$
$
$
98,971
February 8, 2017
February 13, 2017
98,809 November 8, 2016 November 14, 2016
98,051
98,051
August 9, 2016
August 12, 2016
May 9, 2016
May 13, 2016
(a) The distribution was announced on January 27, 2017.
In addition, the holders of our Preferred Units are entitled to receive quarterly cash distributions at an initial distribution rate of
8.50% per annum of the $25.00 liquidation preference per unit (equal to $2.125 per unit per annum) beginning on March 15,
2017 up to, but not including, December 15, 2021. On and after December 15, 2021, distributions on the Preferred Units
accumulate at a percentage of the $25.00 liquidation preference equal to an annual floating rate of the three-month LIBOR plus
a spread of 6.766%. On January 27, 2017, we announced a Preferred Unit distribution of $0.64930556 per unit to be paid on
March 15, 2017 to holders of record as of March 1, 2017 for distributions accumulated from the issuance date up to the
payment date.
Debt Obligations
As of December 31, 2016, we were a party to the following debt agreements:
•
•
•
•
the Revolving Credit Agreement due October 29, 2019, with $839.0 million of borrowings outstanding as of
December 31, 2016;
7.65% senior notes due April 15, 2018 with a face value of $350.0 million; 4.80% senior notes due September 1,
2020 with a face value of $450.0 million; 6.75% senior notes due February 1, 2021 with a face value of $300.0
million; 4.75% senior notes due February 1, 2022 with a face value of $250.0 million; and 7.625% subordinated
notes due January 15, 2043 with a face value of $402.5 million;
$365.4 million in GoZone Bonds due from 2038 to 2041;
line of credit agreements, with $54.0 million of borrowings outstanding as of December 31, 2016; and
• Receivables Financing Agreement due June 15, 2018, with $58.4 million of borrowings outstanding as of
December 31, 2016.
Management believes that we are in compliance with the ratios and covenants contained in our debt instruments. A default
under certain of our debt agreements would be considered an event of default under other of our debt instruments. Please refer
to Note 13 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a
discussion of our debt agreements.
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Credit Ratings
The following table reflects the current outlook and ratings that have been assigned to our debt:
Ratings
Outlook
Standard & Poor’s
Ratings Services
Moody’s Investor
Service Inc.
BB+
Stable
Ba1
Stable
Fitch, Inc.
BB
Stable
The interest rate payable on the 7.65% senior notes due 2018 and the Revolving Credit Agreement is subject to adjustment if
our debt rating is downgraded (or upgraded) by certain credit rating agencies. We may also be required to provide additional
credit support for certain contracts, although as of December 31, 2016, we have not been required to provide any additional
credit support under those contracts due to credit ratings.
Interest Rate Swaps
As of December 31, 2016 and 2015, we were a party to forward-starting interest rate swap agreements for the purpose of
hedging interest rate risk. As of December 31, 2016 and 2015, the aggregate notional amount of these forward-starting interest
rate swaps was $600.0 million. Please refer to Note 2 and Note 17 of the Notes to Consolidated Financial Statements in Item 8.
“Financial Statements and Supplementary Data” and Item 7A. “Quantitative and Qualitative Disclosures about Market Risk”
for a more detailed discussion of our interest rate swaps.
Long-Term Contractual Obligations
The following table presents our long-term contractual obligations and commitments and the related payments due, in total and
by period, as of December 31, 2016:
Payments Due by Period
2017
2018
2019
2020
2021
Thereafter
Total
(Thousands of Dollars)
Long-term debt maturities
$
— $ 408,400
$ 838,992
$ 450,000
$ 300,000
$ 1,017,940
$ 3,015,332
Interest payments (a)
Operating leases (b)
Purchase obligations (c)
145,857
141,742
128,179
31,041
4,088
29,316
2,630
22,718
1,449
103,285
10,861
42
72,808
5,314
—
1,087,423
1,679,294
56,461
—
155,711
8,209
(a) The interest payments calculated for our variable-rate debt are based on forward LIBOR interest rates and the outstanding
borrowings as of December 31, 2016. The interest payments on our fixed-rate debt are based on the stated interest rates and the
outstanding borrowings as of December 31, 2016.
(b) Our operating leases consist primarily of leases for tugs and barges utilized at our St. Eustatius facility and land leases at various
terminal facilities.
(c) A purchase obligation is an enforceable and legally binding agreement to purchase goods or services that specifies significant
terms, including (i) fixed or minimum quantities to be purchased, (ii) fixed, minimum or variable price provisions and (iii) the
approximate timing of the transaction.
We also have pension and other postretirement benefit obligations recorded in “Other long-term liabilities” on our consolidated
balance sheets which have been excluded from the contractual obligations table above due to the uncertainty in timing as to the
future cash flows related to these obligations. For additional information on our pension and other postretirement benefit
obligations see Note 23 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary
Data.”
Environmental, Health and Safety
Our operations are subject to extensive federal, state and local environmental laws and regulations, in the U.S. and in the other
countries in which we operate, including those relating to the discharge of materials into the environment, waste management,
remediation, the characteristics and composition of fuels and pollution prevention measures, among others. Our operations are
also subject to extensive federal, state and local health and safety laws and regulations, including those relating to worker and
pipeline safety, pipeline integrity and operator qualifications. Because more stringent environmental and safety laws and
regulations are continuously being enacted or proposed, the level of future expenditures required for environmental, health and
safety matters is expected to increase in the future.
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The balance of and changes in our accruals for environmental matters as of and for the years ended December 31, 2016 and
2015 are included in Note 14 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and
Supplementary Data.” We believe that we have adequately accrued for our environmental exposures.
Contingencies
We are subject to certain loss contingencies, the outcomes of which could have an adverse effect on our cash flows and results
of operations, as further disclosed in Note 15 of the Notes to Consolidated Financial Statements in Item 8. “Financial
Statements and Supplementary Data.”
RELATED PARTY TRANSACTIONS
Please refer to Note 18 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary
Data” for a discussion of our related party transactions.
CRITICAL ACCOUNTING POLICIES
The preparation of financial statements in accordance with U.S. generally accepted accounting principles requires management
to select accounting policies and to make estimates and assumptions related thereto that affect the amounts reported in the
consolidated financial statements and accompanying notes. Actual results could differ from those estimates. The accounting
policies below are considered critical due to judgments made by management and the sensitivity of these estimates to
deviations of actual results from management’s assumptions. The critical accounting policies should be read in conjunction
with Note 2 of the Notes to the Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data,”
which summarizes our significant accounting policies.
Depreciation
We calculate depreciation expense using the straight-line method over the estimated useful lives of our property, plant and
equipment. Due to the expected long useful lives of our property, plant and equipment, we depreciate our property, plant and
equipment over periods ranging from 5 years to 40 years. Changes in the estimated useful lives of our property, plant and
equipment could have a material adverse effect on our results of operations.
Impairment of Long-Lived Assets
We test long-lived assets for recoverability whenever events or changes in circumstances indicate that the carrying amount of
the asset may not be recoverable. We evaluate recoverability using undiscounted estimated net cash flows generated by the
related asset or asset group. If the results of that evaluation indicate that the undiscounted cash flows are less than the carrying
amount of the asset (i.e., the asset is not recoverable) we perform an impairment analysis. If our intent is to hold the asset for
continued use, we determine the amount of impairment as the amount by which the net carrying value exceeds its fair value. If
our intent is to sell the asset, and the criteria required to classify an asset as held for sale are met, we determine the amount of
impairment as the amount by which the net carrying amount exceeds its fair value less costs to sell.
Impairment of Goodwill
We perform an assessment of goodwill annually or more frequently if events or changes in circumstances warrant. Our
qualitative annual assessment includes, among other things, industry and market considerations, overall financial performance,
other entity-specific events and events affecting individual reporting units. If after assessing the totality of events or
circumstances for each reporting unit, we determine that it is more likely than not that the carrying value exceeds its fair value,
then we perform an impairment test for that reporting unit.
We recognize an impairment of goodwill if the carrying value of goodwill exceeds its estimated fair value. In order to estimate
the fair value of goodwill, management must make certain estimates and assumptions that affect the total fair value of the
reporting unit including, among other things, an assessment of market conditions, projected cash flows, discount rates and
growth rates. Management’s estimates of projected cash flows related to the reporting unit include, but are not limited to, future
earnings of the reporting unit, assumptions about the use or disposition of the asset, estimated remaining life of the asset, and
future expenditures necessary to maintain the asset’s existing service potential.
We calculate the estimated fair value of each of our reporting units using a weighted-average of values calculated using an
income approach and a market approach. The income approach involves estimating the fair value of each reporting unit by
discounting its estimated future cash flows using a discount rate, consistent with a market participant’s assumption. The market
approach bases the fair value measurement on information obtained from observed stock prices of public companies and recent
merger and acquisition transaction data of comparable entities.
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We determined that no impairment charges resulted from our October 1, 2016 impairment assessment. Furthermore, our
assessment did not reflect any reporting units at risk of failing step one of the goodwill impairment test, which compares the
fair value of the reporting unit to its carrying value including goodwill.
Derivative Financial Instruments
We utilize various derivative instruments to manage our exposure to interest rate risk and commodity price risk. We record
derivative instruments in the consolidated balance sheets at fair value, and apply hedge accounting when appropriate. We
record changes to the fair values of derivative instruments in earnings for fair value hedges or as part of accumulated other
comprehensive income (AOCI) for the effective portion of cash flow hedges. We reclassify the effective portion of cash flow
hedges from AOCI to earnings when the underlying forecasted transaction occurs or becomes probable not to occur. We
recognize ineffectiveness resulting from our derivatives immediately in earnings. With respect to cash flow hedges, we must
exercise judgment to assess the probability of the forecasted transaction, which, among other things, depends upon market
factors and our ability to reliably operate our assets.
Defined Benefit Plans
We estimate pension and other postretirement benefit obligations and costs based on actuarial valuations. The annual
measurement date for our pension and other postretirement benefit plans is December 31. The actuarial valuations require the
use of certain assumptions including discount rates, expected long-term rates of return on plan assets and expected rates of
compensation increase. Changes in these assumptions are primarily influenced by factors outside our control. The discount rate
is based on a hypothetical yield curve represented by a series of annualized individual discount rates. Each bond issue
underlying the hypothetical yield curve required an average rating of double-A, when averaging all available ratings by
Moody’s Investor Service Inc., Standard & Poor’s Ratings Services and Fitch, Inc. The resulting discount rates were 4.33% and
4.49% for our pension and other postretirement benefit plans, respectively, as of December 31, 2016. The expected long-term
rate of return on plan assets is based on the weighted averages of the expected long-term rates of return for each asset class of
investments held in our plans as determined using historical data and the assumption that capital markets are informationally
efficient. The expected rate of compensation increase represents average long-term salary increases.
These assumptions can have an effect on the amounts reported in our consolidated financial statements. The effect of a 0.25%
change in the specified assumptions would have the following effects (in thousands):
Increase in benefit obligation as of December 31, 2016 from:
Discount rate decrease
Compensation rate increase
Increase in net periodic benefit cost for the year ending
December 31, 2017 resulting from:
Discount rate decrease
Expected long-term rate of returns on plan assets decrease
Compensation rate increase
Pension
Benefits
Other
Postretirement
Benefits
$
$
5,300
$
1,500
$
400
300
400
400
n/a
100
n/a
n/a
Please refer to Note 23 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary
Data” for further discussion of our pension and other postretirement benefit obligations.
Environmental Liabilities
Environmental remediation costs are expensed and an associated accrual is established when site restoration and environmental
remediation and cleanup obligations are either known or considered probable and can be reasonably estimated. These
environmental obligations are based on estimates of probable undiscounted future costs using currently available technology
and applying current regulations, as well as our own internal environmental policies. The environmental liabilities have not
been reduced by possible recoveries from third parties. Environmental costs include initial site surveys, costs for remediation
and restoration and ongoing monitoring costs, as well as fines, damages and other costs, when estimable. Adjustments to initial
estimates are recorded, from time to time, to reflect changing circumstances and estimates based upon additional information
developed in subsequent periods. Environmental liabilities are difficult to assess and estimate due to unknown factors, such as
the timing and extent of remediation, the determination of our liability in proportion to other parties, improvements in cleanup
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technologies and the extent to which environmental laws and regulations may change in the future. We believe that we have
adequately accrued for our environmental exposures.
Contingencies
We accrue for costs relating to litigation, claims and other contingent matters when such liabilities become probable and
reasonably estimable. Such estimates may be based on advice from third parties or on management’s judgment, as appropriate.
Due to the inherent uncertainty of litigation, actual amounts paid may differ from amounts estimated, and such differences will
be charged to income in the period when final determination is made.
NEW ACCOUNTING PRONOUNCEMENTS
Please refer to Note 3 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary
Data” for a discussion of new accounting pronouncements.
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ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Interest Rate Risk
We manage our exposure to changing interest rates principally through the use of a combination of fixed-rate debt and variable-
rate debt. In addition, we utilize forward-starting interest rate swap agreements to lock in the rate on the interest payments
related to forecasted debt issuances. Borrowings under our variable-rate debt expose us to increases in interest rates.
Please refer to Note 2 and Note 17 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and
Supplementary Data” for a more detailed discussion of our interest rate swaps. The following tables present principal cash
flows and related weighted-average interest rates by expected maturity dates for our long-term debt:
December 31, 2016
Expected Maturity Dates
2017
2018
2019
2020
2021
There-
after
Total
Fair
Value
(Thousands of Dollars, Except Interest Rates)
$ — $350,000
$
— $450,000
$300,000
$652,500
$1,752,500
$1,821,261
—
8.2%
—
4.8%
6.8%
6.5%
6.4%
$ — $ 58,400
$838,992
$
— $
— $365,440
$1,262,832
$1,263,501
—
1.6%
2.5%
—
—%
0.7%
1.9%
December 31, 2015
Expected Maturity Dates
2016
2017
2018
2019
2020
There-
after
Total
Fair
Value
(Thousands of Dollars, Except Interest Rates)
$ — $
— $350,000
$
— $450,000
$952,500
$1,752,500
$1,626,785
—
—
8.2%
—
4.8%
6.6%
6.4%
$ — $
— $ 53,500
$882,664
$
— $365,440
$1,301,604
$1,302,653
—
—
1.2%
2.1%
—
0.1%
1.5%
Long-term Debt:
Fixed-rate
Weighted-average
interest rate
Variable-rate
Weighted-average
interest rate
Long-term Debt:
Fixed-rate
Weighted-average
interest rate
Variable-rate
Weighted-average
interest rate
The following table presents information regarding our forward-starting interest rate swap agreements:
Notional Amount
December 31, 2016
Period of Hedge
(Thousands of Dollars)
$
$
350,000
250,000
600,000
04/2018 - 04/2028
09/2020 - 09/2030
Weighted-Average Fixed
Rate
Fair Value as of December 31,
2016
2015
(Thousands of Dollars)
2.6% $
2.8%
2.7% $
(1,333) $
15
(1,318) $
140
1,163
1,303
Commodity Price Risk
Since the operations of our fuels marketing segment expose us to commodity price risk, we use derivative instruments to
attempt to mitigate the effects of commodity price fluctuations. The derivative instruments we use consist primarily of
commodity futures and swap contracts. Please refer to our derivative financial instruments accounting policy in Note 2 of the
Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further information
on our various types of derivatives.
We have a risk management committee that oversees our trading policies and procedures and certain aspects of risk
management. Our risk management committee also reviews all new risk management strategies in accordance with our risk
management policy, as approved by our board of directors.
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The commodity contracts disclosed below represent only those contracts exposed to commodity price risk at the end of the
period. Please refer to Note 17 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and
Supplementary Data” for the volume and related fair value of all commodity contracts.
Contract
Volumes
(Thousands
of Barrels)
December 31, 2016
Weighted Average
Pay Price
Receive Price
Fair Value of
Current
Asset (Liability)
(Thousands of
Dollars)
Fair Value Hedges:
Futures – long:
(crude oil and refined products)
47
$
55.53
N/A $
2
Futures – short:
(crude oil and refined products)
107
N/A $
58.79
$
(243)
Swaps – long:
(refined products)
Swaps – short:
(refined products)
Economic Hedges and Other Derivatives:
Futures – long:
84
$
45.99
N/A $
141
573
N/A $
41.87
$
(3,322)
(crude oil and refined products)
18
$
72.06
N/A $
Futures – short:
(crude oil and refined products)
9
N/A $
71.88
$
10
(7)
Swaps – long:
(refined products)
Swaps – short:
(refined products)
Forward purchase contracts:
(crude oil)
Forward sales contracts:
(crude oil)
869
$
42.20
N/A $
4,737
874
N/A $
41.40
$
(5,459)
310
$
52.78
N/A $
499
310
N/A $
52.76
$
(507)
Total fair value of open positions exposed to
commodity price risk
$
(4,149)
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Fair Value Hedges:
Futures – long:
Contract
Volumes
(Thousands
of Barrels)
December 31, 2015
Weighted Average
Pay Price
Receive Price
Fair Value of
Current
Asset (Liability)
(Thousands of
Dollars)
(crude oil and refined products)
38
$
37.85
N/A $
Futures – short:
(crude oil and refined products)
59
N/A $
39.07
$
1
68
Swaps – long:
(refined products)
Swaps – short:
(refined products)
Economic Hedges and Other Derivatives:
Futures – long:
129
$
23.83
N/A $
(18)
784
N/A $
26.28
$
1,864
(crude oil and refined products)
87
$
44.81
N/A $
(48)
Futures – short:
(crude oil and refined products)
196
N/A $
43.54
$
149
Swaps – long:
(refined products)
Swaps – short:
(refined products)
Forward purchase contracts:
(crude oil)
Forward sales contracts:
(crude oil)
1,532
$
28.19
N/A $
(8,529)
1,435
N/A $
33.01
$
14,931
248
$
36.99
N/A $
193
248
N/A $
36.82
$
(235)
Total fair value of open positions exposed to
commodity price risk
$
8,376
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ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Management’s Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining effective internal control over financial reporting as defined in
Rule 13a-15(f) under the Securities Exchange Act of 1934. Our management assessed the effectiveness of NuStar Energy L.P.’s
internal control over financial reporting as of December 31, 2016. In its evaluation, management used the criteria set forth by
the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework
(2013). Based on this assessment, management believes that, as of December 31, 2016, our internal control over financial
reporting was effective based on those criteria.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore,
even those systems determined to be effective can provide only reasonable assurance with respect to financial statement
preparation and presentation.
The effectiveness of internal control over financial reporting as of December 31, 2016 has been audited by KPMG LLP, the
independent registered public accounting firm who audited our consolidated financial statements included in this Form 10-K.
KPMG LLP’s attestation on the effectiveness of our internal control over financial reporting appears on page 61.
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Report of Independent Registered Public Accounting Firm
The Board of Directors of NuStar GP, LLC
and Unitholders of NuStar Energy L.P.:
We have audited the accompanying consolidated balance sheets of NuStar Energy L.P. (a Delaware limited partnership) and
subsidiaries (the Partnership) as of December 31, 2016 and 2015, and the related consolidated statements of income,
comprehensive income, partners’ equity, and cash flows for each of the years in the three-year period ended December 31,
2016. These consolidated financial statements are the responsibility of the Partnership’s management. Our responsibility is to
express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).
Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial
position of NuStar Energy L.P. and subsidiaries as of December 31, 2016 and 2015, and the results of their operations and their
cash flows for each of the years in the three-year period ended December 31, 2016, in conformity with U.S. generally accepted
accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States),
NuStar Energy L.P. and subsidiaries’ internal control over financial reporting as of December 31, 2016, based on criteria
established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO), and our report dated February 23, 2017 expressed an unqualified opinion on the effectiveness
of the Partnership’s internal control over financial reporting.
/s/ KPMG LLP
San Antonio, Texas
February 23, 2017
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Report of Independent Registered Public Accounting Firm
The Board of Directors of NuStar GP, LLC
and Unitholders of NuStar Energy L.P.:
We have audited NuStar Energy L.P. (a Delaware limited partnership) and subsidiaries’ (the Partnership’s) internal control over
financial reporting as of December 31, 2016, based on criteria established in Internal Control – Integrated Framework (2013)
issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Partnership’s management is
responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of
internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over
Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting
based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States).
Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal
control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of
internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design
and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other
procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our
opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally
accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures
that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and
dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit
preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and
expenditures of the company are being made only in accordance with authorizations of management and directors of the
company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or
disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, NuStar Energy L.P. and subsidiaries maintained, in all material respects, effective internal control over financial
reporting as of December 31, 2016, based on criteria established in Internal Control – Integrated Framework (2013) issued by
COSO.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States),
the consolidated balance sheets of NuStar Energy L.P. and subsidiaries as of December 31, 2016 and 2015, and the related
consolidated statements of income, comprehensive income, partners’ equity, and cash flows for each of the years in the three-
year period ended December 31, 2016, and our report dated February 23, 2017 expressed an unqualified opinion on those
consolidated financial statements.
/s/ KPMG LLP
San Antonio, Texas
February 23, 2017
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Thousands of Dollars, Except Unit Data)
Current assets:
Assets
Cash and cash equivalents
Accounts receivable, net of allowance for doubtful accounts of $7,756 and $8,473
as of December 31, 2016 and 2015, respectively
Receivable from related party
Inventories
Other current assets
Total current assets
Property, plant and equipment, at cost
Accumulated depreciation and amortization
Property, plant and equipment, net
Intangible assets, net
Goodwill
Deferred income tax asset
Other long-term assets, net
Total assets
Liabilities and Partners’ Equity
Current liabilities:
Accounts payable
Payable to related party
Short-term debt
Accrued interest payable
Accrued liabilities
Taxes other than income tax
Income tax payable
Total current liabilities
Long-term debt
Long-term payable to related party
Deferred income tax liability
Other long-term liabilities
Commitments and contingencies (Note 15)
Partners’ equity:
Series A preferred limited partners (9,060,000 preferred units outstanding
as of December 31, 2016)
Common limited partners (78,616,228 and 77,886,078 common units outstanding
as of December 31, 2016 and 2015, respectively)
General partner
Accumulated other comprehensive loss
Total partners’ equity
Total liabilities and partners’ equity
See Notes to Consolidated Financial Statements.
62
December 31,
2016
2015
$
35,942
$
118,862
170,293
317
37,945
132,686
377,183
5,435,278
(1,712,995)
3,722,283
127,083
696,637
2,051
105,308
5,030,545
118,686
—
54,000
34,030
60,485
15,685
6,510
289,396
3,014,364
—
22,204
92,964
$
$
145,064
—
38,749
31,176
333,851
5,209,160
(1,525,589)
3,683,571
112,011
696,637
2,858
296,597
5,125,525
125,147
14,799
84,000
34,286
55,194
12,810
5,977
332,213
3,055,612
32,080
24,810
70,966
218,400
—
1,455,642
31,752
(94,177)
1,611,617
5,030,545
$
1,661,900
36,738
(88,794)
1,609,844
5,125,525
$
$
$
NUSTAR ENERGY L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(Thousands of Dollars, Except Unit and Per Unit Data)
Table of Contents
Revenues:
Service revenues
Product sales
Total revenues
Costs and expenses:
Cost of product sales
Operating expenses:
Third parties
Related party
Total operating expenses
General and administrative expenses:
Third parties
Related party
Total general and administrative expenses
Depreciation and amortization expense
Total costs and expenses
Operating income
Equity in earnings of joint ventures
Interest expense, net
Interest income from related party
Other (expense) income, net
Income from continuing operations before income tax expense
Income tax expense
Income from continuing operations
Income (loss) from discontinued operations, net of tax
Net income
Less loss attributable to noncontrolling interest
Net income attributable to NuStar Energy L.P.
Basic and diluted net income (loss) per common unit:
Continuing operations
Discontinued operations
Total (Note 21)
Year Ended December 31,
2016
2015
2014
$ 1,083,165
673,517
1,756,682
$ 1,114,153
969,887
2,084,040
$ 1,026,446
2,048,672
3,075,118
633,653
907,574
1,967,528
426,686
21,681
448,367
88,324
10,493
98,817
216,736
1,397,573
359,109
—
(138,350)
—
(58,783)
161,976
11,973
150,003
—
150,003
—
150,003
1.27
—
1.27
$
$
$
337,466
135,565
473,031
35,752
66,769
102,521
210,210
1,693,336
390,704
—
(131,868)
—
61,822
320,658
14,712
305,946
774
306,720
—
306,720
3.29
0.01
3.30
$
$
$
347,189
125,736
472,925
29,146
66,910
96,056
191,708
2,728,217
346,901
4,796
(132,281)
1,055
4,499
224,970
10,801
214,169
(3,791)
210,378
(395)
210,773
2.14
(0.04)
2.10
$
$
$
Basic weighted-average common units outstanding
78,080,484
77,886,078
77,886,078
Diluted weighted-average common units outstanding
78,113,002
77,886,078
77,886,078
See Notes to Consolidated Financial Statements.
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Thousands of Dollars)
Net income
Other comprehensive loss:
Foreign currency translation adjustment
Net loss on pension and other postretirement benefit adjustments, net of
income tax benefit of $60
Net gain on cash flow hedges
Total other comprehensive loss
Comprehensive income
Less comprehensive loss attributable to noncontrolling interest
Year Ended December 31,
2016
2015
2014
$
150,003
$
306,720
$
210,378
(8,243)
(31,987)
(15,614)
(2,850)
5,710
(5,383)
—
11,105
(20,882)
144,620
285,838
—
—
—
10,663
(4,951)
205,427
(828)
206,255
Comprehensive income attributable to NuStar Energy L.P.
$
144,620
$
285,838
$
See Notes to Consolidated Financial Statements.
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Thousands of Dollars)
Cash Flows from Operating Activities:
Net income
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation and amortization expense
Unit-based compensation expense
Amortization of debt related items
Loss (gain) on sale or disposition of assets
Gain associated with the Linden Acquisition
Impairment loss
Deferred income tax (benefit) expense
Equity in earnings of joint ventures
Distributions of equity in earnings of joint ventures
Changes in current assets and current liabilities (Note 22)
Other, net
Net cash provided by operating activities
Cash Flows from Investing Activities:
Capital expenditures
Change in accounts payable related to capital expenditures
Acquisitions
Investment in other long-term assets
Proceeds from sale or disposition of assets
Proceeds from insurance recoveries
Increase in note receivable from Axeon
Other, net
Net cash used in investing activities
Cash Flows from Financing Activities:
Proceeds from long-term debt borrowings
Proceeds from short-term debt borrowings
Long-term debt repayments
Short-term debt repayments
Proceeds from issuance of preferred units, net of issuance costs
Proceeds from issuance of common units, net of issuance costs
Contributions from general partner
Distributions to common unitholders and general partner
(Decrease) increase in cash book overdrafts
Other, net
Net cash used in financing activities
Effect of foreign exchange rate changes on cash
Net (decrease) increase in cash and cash equivalents
Cash and cash equivalents as of the beginning of the period
Cash and cash equivalents as of the end of the period
Year Ended December 31,
2016
2015
2014
$
150,003
$
306,720
$
210,378
216,736
210,210
191,708
7,579
7,477
64
—
58,655
(469)
—
—
3,716
(7,000)
436,761
(204,358)
(11,063)
(95,657)
—
—
—
—
—
(311,078)
752,729
654,000
(772,152)
(684,000)
218,400
27,710
680
(392,962)
(11,237)
(4,492)
(211,324)
2,721
(82,920)
118,862
—
8,840
(1,617)
(56,277)
—
2,058
—
2,500
50,559
1,944
524,937
(324,808)
(3,156)
(142,500)
(3,564)
17,132
4,867
—
—
(452,029)
860,131
823,500
(500,410)
(816,500)
—
—
—
(392,204)
(2,954)
(792)
(29,229)
(12,729)
30,950
87,912
—
8,969
(3,853)
—
4,201
3,467
(4,796)
7,587
82,418
18,444
518,523
(356,965)
4,903
—
—
26,012
—
(13,328)
(853)
(340,231)
743,719
574,900
(623,770)
(497,900)
—
—
—
(392,204)
12,851
(5,781)
(188,185)
(2,938)
(12,831)
100,743
$
35,942
$
118,862
$
87,912
See Notes to Consolidated Financial Statements.
65
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Balance as of
January 1, 2014
Net income (loss)
Other comprehensive
loss
Distributions
to partners
Other
Balance as of
December 31, 2014
Net income
Other comprehensive
loss
Distributions
to partners
Balance as of
December 31, 2015
Net income
Other comprehensive
loss
Distributions
to partners
Issuance of units,
including
contribution from
general partner
Unit-based
compensation
Balance as of
December 31, 2016
—
—
—
—
—
—
—
—
—
—
—
—
NUSTAR ENERGY L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF PARTNERS’ EQUITY
Years Ended December 31, 2016, 2015 and 2014
(Thousands of Dollars, Except Unit Data)
Limited Partners
Series A Preferred
Common
Units
Amount
Units
Amount
Accumulated
Other
Comprehensive
Loss
Total NuStar
Energy L.P.
Partners’
Equity
General
Partner
Noncontrolling
Interest
Total
Partners’
Equity
— $
— 77,886,078
$1,921,726
$ 43,804
$
(63,394) $ 1,902,136
$
1,658
$ 1,903,794
—
—
—
—
—
—
—
—
164,201
46,572
—
210,773
(395)
210,378
—
—
(4,518)
(4,518)
(433)
(4,951)
(341,140)
(51,064)
23
—
—
—
(392,204)
—
(392,204)
23
(830)
(807)
— 77,886,078
1,744,810
39,312
(67,912)
1,716,210
—
—
—
—
—
—
258,230
48,490
—
306,720
—
—
(20,882)
(20,882)
(341,140)
(51,064)
—
(392,204)
— 77,886,078
1,661,900
36,738
(88,794)
1,609,844
1,925
—
(1,925)
—
—
—
102,580
45,498
—
150,003
—
—
(5,383)
(5,383)
(341,798)
(51,164)
—
(394,887)
—
—
—
—
—
—
—
—
—
—
1,716,210
306,720
(20,882)
(392,204)
1,609,844
150,003
(5,383)
(394,887)
246,685
5,355
9,060,000
218,400
595,050
27,710
—
—
135,100
5,250
575
105
—
—
246,685
5,355
9,060,000
$ 218,400
78,616,228
$1,455,642
$ 31,752
$
(94,177) $ 1,611,617
$
— $ 1,611,617
See Notes to Consolidated Financial Statements.
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2016, 2015 and 2014
1. ORGANIZATION AND OPERATIONS
Organization
NuStar Energy L.P. (NYSE: NS) is engaged in the transportation of petroleum products and anhydrous ammonia, the
terminalling and storage of petroleum products and the marketing of petroleum products. Unless otherwise indicated, the terms
“NuStar Energy,” “NS,” “the Partnership,” “we,” “our” and “us” are used in this report to refer to NuStar Energy L.P., to one or
more of our consolidated subsidiaries or to all of them taken as a whole. NuStar GP Holdings, LLC (NuStar GP Holdings or
NSH) (NYSE: NSH) owns our general partner, Riverwalk Logistics, L.P., and owns an approximate 13% common limited
partner interest in us as of December 31, 2016.
Employee Transfer from NuStar GP, LLC. On March 1, 2016, NuStar GP, LLC, the general partner of our general partner and a
wholly owned subsidiary of NuStar GP Holdings, transferred and assigned to NuStar Services Company LLC (NuStar Services
Co), a wholly owned subsidiary of NuStar Energy, all of NuStar GP, LLC’s employees and related benefit plans, programs,
contracts and policies (the Employee Transfer). As a result of the Employee Transfer, we pay employee costs directly and
sponsor the long-term incentive plan and other employee benefit plans. Please refer to Note 18 for further discussion of the
Employee Transfer and our related party agreements, Note 23 for a discussion of our employee benefit plans and Note 24 for a
discussion of our long-term incentive plan.
Operations
We conduct our operations through our subsidiaries, primarily NuStar Logistics, L.P. (NuStar Logistics) and NuStar Pipeline
Operating Partnership L.P. (NuPOP). We have three business segments: pipeline, storage and fuels marketing.
Pipeline. We own 3,140 miles of refined product pipelines and 1,230 miles of crude oil pipelines, as well as approximately 4.0
million barrels of storage capacity, which comprise our Central West System. In addition, we own 2,370 miles of refined
product pipelines, consisting of the East and North Pipelines, and a 2,000 mile ammonia pipeline, which comprise our Central
East System. The East and North Pipelines have storage capacity of approximately 6.7 million barrels. We charge tariffs on a
per barrel basis for transporting refined products, crude oil and other feedstocks in our refined product and crude oil pipelines
and on a per ton basis for transporting anhydrous ammonia in the Ammonia Pipeline.
Storage. We own terminal and storage facilities in the United States, Canada, Mexico, the Netherlands, including St. Eustatius
in the Caribbean, and the United Kingdom, with approximately 84.9 million barrels of storage capacity. Our terminal and
storage facilities provide storage, handling and other services on a fee basis for petroleum products, crude oil, specialty
chemicals and other liquids.
Fuels Marketing. Within our fuels marketing operations, we purchase crude oil and refined petroleum products for resale. The
activities of the fuels marketing segment expose us to the risk of fluctuations in commodity prices, which has a direct impact on
the segment’s results of operations. We enter into derivative contracts to attempt to mitigate the effect of commodity price
fluctuations.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Consolidation
The accompanying consolidated financial statements represent the consolidated operations of the Partnership and our
subsidiaries. Noncontrolling interests are separately disclosed on the financial statements. Inter-partnership balances and
transactions have been eliminated in consolidation. The operations of certain pipelines and terminals in which we own an
undivided interest are proportionately consolidated in the accompanying consolidated financial statements.
Use of Estimates
The preparation of consolidated financial statements in conformity with U.S. generally accepted accounting principles (GAAP)
requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial
statements and accompanying notes. Actual results could differ from those estimates. On an ongoing basis, management
reviews their estimates based on currently available information. Management may revise estimates due to changes in facts and
circumstances.
Cash and Cash Equivalents
Cash equivalents are all highly liquid investments with an original maturity of three months or less when acquired.
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Accounts Receivable
Accounts receivable represent valid claims against non-affiliated customers for products sold or services rendered. We extend
credit terms to certain customers after review of various credit indicators, including the customer’s credit rating. Outstanding
customer receivable balances are regularly reviewed for possible non-payment indicators and allowances for doubtful accounts
are recorded based upon management’s estimate of collectability at the time of their review.
Inventories
Inventories consist of crude oil, refined petroleum products and materials and supplies. Inventories, except those associated
with a qualifying fair value hedge, are valued at the lower of cost or market. Cost is determined using the weighted-average
cost method. Our inventory, other than materials and supplies, consists of one end-product category, petroleum products, which
we include in the fuels marketing segment. Accordingly, we determine lower of cost or market adjustments on an aggregate
basis. Inventories associated with qualifying fair value hedges are valued at current market prices. Materials and supplies are
valued at the lower of average cost or market.
Property, Plant and Equipment
We record additions to property, plant and equipment, including reliability and strategic capital expenditures, at cost. Repair
and maintenance costs associated with existing assets that are minor in nature and do not extend the useful life of existing
assets are charged to operating expenses as incurred. Depreciation of property, plant and equipment is recorded on a straight-
line basis over the estimated useful lives of the related assets. When property or equipment is retired, sold or otherwise
disposed of, the difference between the carrying value and the net proceeds is recognized in “Other (expense) income, net” in
the consolidated statements of income in the year of disposition.
We capitalize overhead costs and interest costs incurred on funds used to construct property, plant and equipment while the
asset is under construction. The overhead costs and capitalized interest are recorded as part of the asset to which they relate and
are amortized over the asset’s estimated useful life as a component of depreciation expense.
Goodwill
We assess goodwill for impairment annually on October 1, or more frequently if events or changes in circumstances indicate it
might be impaired. We have the option to first assess qualitative factors to determine whether it is necessary to perform a
quantitative goodwill impairment test. We performed a quantitative goodwill impairment test as of October 1, 2016 and 2015,
and we determined that no impairment charges occurred.
We calculate the estimated fair value of each of our reporting units using a weighted-average of values calculated using an
income approach and a market approach. The income approach involves estimating the fair value of each reporting unit by
discounting its estimated future cash flows using a discount rate that would be consistent with a market participant’s
assumption. The market approach bases the fair value measurement on information obtained from observed stock prices of
public companies and recent merger and acquisition transaction data of comparable entities.
Our reporting units to which goodwill has been allocated consist of the following:
•
•
•
•
crude oil pipelines;
refined product pipelines;
terminals, excluding our St. Eustatius and Point Tupper facilities; and
bunkering activity at our St. Eustatius and Point Tupper facilities.
The quantitative impairment test for goodwill consists of a two-step process. Step 1 compares the fair value of the reporting
unit to its carrying value including goodwill. The carrying value of each reporting unit equals the total identified assets
(including goodwill) less the sum of each reporting unit’s identified liabilities. We used reasonable and supportable methods to
assign the assets and liabilities to the appropriate reporting units in a consistent manner. If the carrying value exceeds fair value,
there is a potential impairment and step 2 must be performed to determine the amount of goodwill impairment. Step 2 compares
the carrying value of the reporting unit’s goodwill to its implied fair value using a hypothetical allocation of the reporting unit’s
fair value. If the goodwill carrying value exceeds its implied fair value, the excess is reported as impairment.
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Investment in Joint Ventures
We account for investment in joint ventures using the equity method of accounting. We reported our portion of the results of
operations for our equity method investments in “Equity in earnings of joint ventures” in the consolidated statements of
income. On January 2, 2015, we acquired full ownership of ST Linden Terminal, LLC (Linden), which owns a refined products
terminal in Linden, NJ with 4.3 million barrels of storage capacity (the Linden Acquisition). See Note 4 for additional
information on the Linden Acquisition. On February 26, 2014, we sold our remaining 50% ownership interest in Axeon
Specialty Products LLC. See Note 5 for additional discussion.
Impairment of Long-Lived Assets
We review long-lived assets, including property, plant and equipment, for impairment whenever events or changes in
circumstances indicate that the carrying amount may not be recoverable. We evaluate recoverability using undiscounted
estimated net cash flows generated by the related asset or asset group. If the results of that evaluation indicate that the
undiscounted cash flows are less than the carrying amount of the asset (i.e., the asset is not recoverable) we perform an
impairment analysis. If our intent is to hold the asset for continued use, we determine the amount of impairment as the amount
by which the net carrying value exceeds its fair value. If our intent is to sell the asset, and the criteria required to classify an
asset as held for sale are met, we determine the amount of impairment as the amount by which the net carrying amount exceeds
its fair value less costs to sell. We believe that the carrying amounts of our long-lived assets as of December 31, 2016 are
recoverable.
Income Taxes
We are a limited partnership and generally are not subject to federal or state income taxes. Accordingly, our taxable income or
loss, which may vary substantially from income or loss reported for financial reporting purposes, is generally included in the
federal and state income tax returns of our partners. For transfers of publicly held units subsequent to our initial public offering,
we have made an election permitted by Section 754 of the Internal Revenue Code (the Code) to adjust the common unit
purchaser’s tax basis in our underlying assets to reflect the purchase price of the units. This results in an allocation of taxable
income and expenses to the purchaser of the common units, including depreciation deductions and gains and losses on sales of
assets, based upon the new unitholder’s purchase price for the common units.
We conduct certain of our operations through taxable wholly owned corporate subsidiaries. We account for income taxes
related to our taxable subsidiaries using the asset and liability method. Under this method, we recognize deferred tax assets and
liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts of
existing assets and liabilities and their respective tax bases. We measure deferred taxes using enacted tax rates expected to
apply to taxable income in the year those temporary differences are expected to be recovered or settled.
We recognize a tax position if it is more-likely-than-not that the tax position will be sustained, based on the technical merits of
the position, upon examination. We record uncertain tax positions in the financial statements at the largest amount of benefit
that is more-likely-than-not to be realized. We had no unrecognized tax benefits as of December 31, 2016 and 2015.
NuStar Energy and certain of its subsidiaries file income tax returns in the U.S. federal jurisdiction and various state and
foreign jurisdictions. For U.S. federal and state purposes, as well as for our major non-U.S. jurisdictions, tax years subject to
examination are 2012 through 2015, according to standard statute of limitations.
Asset Retirement Obligations
We record a liability for asset retirement obligations at the fair value of the estimated costs to retire a tangible long-lived asset
at the time we incur that liability, which is generally when the asset is purchased, constructed or leased, when we have a legal
obligation to incur costs to retire the asset and when a reasonable estimate of the fair value of the obligation can be made. If a
reasonable estimate cannot be made at the time the liability is incurred, we record the liability when sufficient information is
available to estimate the fair value.
We have asset retirement obligations with respect to certain of our assets due to various legal obligations to clean and/or
dispose of those assets at the time they are retired. However, these assets can be used for an extended and indeterminate period
of time as long as they are properly maintained and/or upgraded. It is our practice and current intent to maintain our assets and
continue making improvements to those assets based on technological advances. As a result, we believe that our assets have
indeterminate lives for purposes of estimating asset retirement obligations because dates or ranges of dates upon which we
would retire these assets cannot reasonably be estimated at this time. When a date or range of dates can reasonably be estimated
for the retirement of any asset, we estimate the costs of performing the retirement activities and record a liability for the fair
value of these costs.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
We also have legal obligations in the form of leases and right-of-way agreements, which require us to remove certain of our
assets upon termination of the agreement. However, these lease or right-of-way agreements generally contain automatic
renewal provisions that extend our rights indefinitely or we have other legal means available to extend our rights. We have
recorded a liability of approximately $0.6 million as of December 31, 2016 and 2015, which is included in “Other long-term
liabilities” in the consolidated balance sheets, for conditional asset retirement obligations related to the retirement of terminal
assets with lease and right-of-way agreements.
Environmental Remediation Costs
Environmental remediation costs are expensed and an associated accrual established when site restoration and environmental
remediation and cleanup obligations are either known or considered probable and can be reasonably estimated. These
environmental obligations are based on estimates of probable undiscounted future costs using currently available technology
and applying current regulations, as well as our own internal environmental policies. The environmental liabilities have not
been reduced by possible recoveries from third parties. Environmental costs include initial site surveys, costs for remediation
and restoration and ongoing monitoring costs, as well as fines, damages and other costs, when estimable. Adjustments to initial
estimates are recorded, from time to time, to reflect changing circumstances and estimates based upon additional information
developed in subsequent periods.
Product Imbalances
We incur product imbalances as a result of variances in pipeline meter readings and volume fluctuations within the East
Pipeline system due to pressure and temperature changes. We use quoted market prices as of the reporting date to value our
assets and liabilities related to product imbalances. Product imbalance liabilities are included in “Accrued liabilities” and
product imbalance assets are included in “Other current assets” in the consolidated balance sheets.
Revenue Recognition
Revenues for the pipeline segment are derived from interstate and intrastate pipeline transportation of refined product, crude oil
and anhydrous ammonia. Transportation revenues (based on pipeline tariffs) are recognized as the refined product, crude oil or
anhydrous ammonia is delivered out of the pipelines.
Revenues for the storage segment include fees for tank storage agreements, whereby a customer agrees to pay for a certain
amount of storage in a tank over a period of time (storage terminal revenues), and throughput agreements, whereby a customer
pays a fee per barrel for volumes moving through our terminals (throughput terminal revenues). Our terminals also provide
blending, additive injections, handling and filtering services for which we charge additional fees. Certain of our facilities
charge fees to provide marine services such as pilotage, tug assistance, line handling, launch service, emergency response
services and other ship services. Storage terminal revenues are recognized when services are provided to the customer.
Throughput revenues are recognized as refined products or crude oil are received in or delivered out of our terminal and as
crude oil and certain other refinery feedstocks are received by the related refinery. Revenues for marine services are recognized
as those services are provided.
Revenues from the sale of petroleum products, which are included in our fuels marketing segment, are recognized when
product is delivered to the customer and title and risk pass to the customer.
We collect taxes on certain revenue transactions to be remitted to governmental authorities, which may include sales, use, value
added and some excise taxes. These taxes are not included in revenue.
Income Allocation
Our partnership agreement, as amended, sets forth the calculation to be used to determine the amount and priority of cash
distributions that the unitholders and general partner will receive. The partnership agreement also contains provisions for the
allocation of net income to the unitholders and the general partner; however, losses are only allocated to the common
unitholders and the general partner. Our net income for each quarterly reporting period is first allocated to the preferred limited
partner unitholders in an amount equal to the earned distributions for the respective reporting period and then to the general
partner in an amount equal to the general partner’s incentive distribution calculated based upon the declared distribution for the
respective reporting period. We allocate the remaining net income or loss among the common unitholders (98%) and general
partner (2%), as set forth in our partnership agreement.
Basic and Diluted Net Income Per Common Unit
Basic and diluted net income per common unit is determined pursuant to the two-class method. Under this method, all earnings
are allocated to our common limited partners and participating securities based on their respective rights to receive distributions
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
earned during the period. Participating securities include our general partner interest and restricted units awarded under our
long-term incentive plan.
We compute basic net income per common unit by dividing net income attributable to our common limited partners by the
weighted-average number of common units outstanding during the period. We compute diluted net income per common unit by
dividing net income attributable to our common limited partners by the sum of (i) the weighted-average number of common
units outstanding during the period and (ii) the effect of dilutive potential common units outstanding during the period. Dilutive
potential common units include contingently issuable performance units awarded under our long-term incentive plan. See Note
24 for additional information on our performance units.
Derivative Financial Instruments
We formally document all relationships between hedging instruments and hedged items. This process includes identification of
the hedging instrument and the hedged transaction, the nature of the risk being hedged and how the hedging instrument’s
effectiveness will be assessed. To qualify for hedge accounting, at inception of the hedge we assess whether the derivative
instruments that are used in our hedging transactions are expected to be highly effective in offsetting changes in cash flows or
the fair value of the hedged items. Throughout the designated hedge period and at least quarterly, we assess whether the
derivative instruments are highly effective and continue to qualify for hedge accounting. To assess the effectiveness of the
hedging relationship both prospectively and retrospectively, we use regression analysis to calculate the correlation of the
changes in the fair values of the derivative instrument and related hedged item.
We record commodity derivative instruments in the consolidated balance sheets at fair value. We recognize mark-to-market
adjustments for derivative instruments designated and qualifying as fair value hedges (Fair Value Hedges) and the related
change in the fair value of the associated hedged physical inventory or firm commitment within “Cost of product sales.” For
derivative instruments designated and qualifying as cash flow hedges (Cash Flow Hedges), we record the effective portion of
mark-to-market adjustments as a component of accumulated other comprehensive income (loss) (AOCI) until the underlying
hedged forecasted transactions occur. Any hedge ineffectiveness is recognized immediately in “Cost of product sales.” Once a
hedged transaction occurs, we reclassify the effective portion from AOCI to “Cost of product sales.” If it becomes probable that
a hedged transaction will not occur, then the associated gains or losses are reclassified from AOCI to “Cost of product sales”
immediately. For derivative instruments that have associated underlying physical inventory but do not qualify for hedge
accounting (Economic Hedges and Other Derivatives), we record the mark-to-market adjustments in “Cost of product sales.”
Under the terms of our forward-starting interest rate swap agreements, we pay a fixed rate and receive a variable rate. We
entered into the forward-starting swaps in order to hedge the risk of changes in the interest payments attributable to changes in
the benchmark interest rate during the period from the effective date of the swap to the issuance of the forecasted debt. We
account for the forward-starting interest rate swaps as Cash Flow Hedges, and we recognize the fair value of each interest rate
swap in the consolidated balance sheets. We record the effective portion of mark-to-market adjustments as a component of
AOCI, and any hedge ineffectiveness is recognized immediately in “Interest expense, net.” The amount accumulated in AOCI
is amortized into “Interest expense, net” as the forecasted interest payments occur or if the interest payments are probable not to
occur.
We classify cash flows associated with our derivative instruments as operating cash flows in the consolidated statements of
cash flows, except for receipts or payments associated with terminated forward-starting interest rate swap agreements, which
are included in cash flows from financing activities. See Note 17 for additional information regarding our derivative financial
instruments.
Operating Leases
We recognize rent expense on a straight-line basis over the lease term, including the impact of both scheduled rent increases
and free or reduced rents (commonly referred to as “rent holidays”).
Unit-based Compensation
Unit-based compensation for our long-term incentive plan is recorded in our consolidated balance sheets based on the fair value
of the awards granted and recognized as compensation expense primarily on a straight-line basis over the requisite service
period. Certain awards issued under our long-term incentive plan provide that the grantee’s award vests immediately upon
retirement. Compensation expense is recognized immediately if these awards are granted to retirement-eligible employees, as
defined in each award. In addition, if, during a vesting period of a grant, the grantee will become retirement-eligible, then
compensation expense associated with the grant is recognized from the grant date through the grantee’s retirement eligibility
date.
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Forfeitures of our unit-based compensation awards are recognized as an adjustment to compensation expense when they occur.
Unit-based compensation expense is included in “General and administrative expenses” on our consolidated statements of
income. See Note 24 for additional information regarding our unit-based compensation.
Margin Deposits
Margin deposits relate to our exchange-traded derivative contracts and generally vary based on changes in the value of the
contracts. Margin deposits are included in “Other current assets” in the consolidated balance sheets.
Foreign Currency Translation
The functional currencies of our foreign subsidiaries are the local currency of the country in which the subsidiary is located,
except for our subsidiaries located in St. Eustatius in the Caribbean (formerly the Netherlands Antilles), whose functional
currency is the U.S. dollar. The assets and liabilities of our foreign subsidiaries with local functional currencies are translated to
U.S. dollars at period-end exchange rates, and income and expense items are translated to U.S. dollars at weighted-average
exchange rates in effect during the period. These translation adjustments are included in “Accumulated other comprehensive
loss” in the equity section of the consolidated balance sheets. Gains and losses on foreign currency transactions are included in
“Other (expense) income, net” in the consolidated statements of income.
Reclassifications
Certain previously reported amounts in the 2015 consolidated financial statements and notes have been reclassified to conform
to 2016 presentation.
3. NEW ACCOUNTING PRONOUNCEMENTS
Goodwill
In January 2017, the Financial Accounting Standards Board (FASB) issued amended guidance that simplifies the accounting for
goodwill impairment by eliminating step 2 of the goodwill impairment test. Under the amended guidance, goodwill impairment
will be measured as the excess of the reporting unit’s carrying value over its fair value, not to exceed the carrying amount of
goodwill for that reporting unit. The changes are effective for annual and interim periods beginning after December 15, 2019,
and amendments should be applied prospectively. Early adoption is permitted for any impairment tests performed after
January 1, 2017. We are currently evaluating whether we will early adopt these provisions. However, we do not expect the
guidance to have a material impact on our financial position, results of operations or disclosures.
Definition of a Business
In January 2017, the FASB issued amended guidance that clarifies the definition of a business used in evaluating whether a set
of transferred assets and activities constitutes a business. Under the amended guidance, if substantially all of the fair value of
the gross assets acquired is concentrated in a single identifiable asset or a group of similar identifiable assets, the set of
transferred assets and activities would not represent a business. To be considered a business, the set of assets transferred is
required to include at least one substantive process that together significantly contribute to the ability to create outputs. In
addition, the amended guidance narrows the definition of outputs to be consistent with how outputs are described in the new
revenue recognition standard. The changes are effective for annual and interim periods beginning after December 15, 2017, and
amendments should be applied prospectively. We are currently evaluating whether we will early adopt these provisions.
However, we do not expect the guidance to have a material impact on our financial position, results of operations or
disclosures.
Statement of Cash Flows
In August 2016, the FASB issued amended guidance that clarifies how entities should present certain cash receipts and cash
payments on the statement of cash flows, including but not limited to debt prepayment or debt extinguishment costs; contingent
consideration payments made after a business combination; proceeds from the settlement of insurance claims and distributions
received from equity method investees. The changes are effective for annual and interim periods beginning after
December 15, 2017, and amendments should be applied retrospectively. We will adopt these provisions January 1, 2018, and we
do not expect the guidance to have a material impact on our statements of cash flows or disclosures.
Credit Losses
In June 2016, the FASB issued amended guidance that requires the use of a “current expected loss” model for financial assets
measured at amortized cost and certain off-balance sheet credit exposures. Under this model, entities will be required to
estimate the lifetime expected credit losses on such instruments based on historical experience, current conditions, and
reasonable and supportable forecasts. This amended guidance also expands the disclosure requirements to enable users of
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
financial statements to understand an entity’s assumptions, models and methods for estimating expected credit losses. The
changes are effective for annual and interim periods beginning after December 15, 2019, and amendments should be applied
using a modified retrospective approach. We are currently assessing the impact of this amended guidance on our financial
position, results of operations and disclosures.
Unit-Based Payments
In March 2016, the FASB issued amended guidance that simplifies certain aspects of accounting for unit-based payments to
employees, including the accounting for income taxes, forfeitures, and statutory tax withholding requirements, as well as
classification in the statement of cash flows. The changes are effective for annual and interim periods beginning after
December 15, 2016, and early adoption is permitted. Prior to the Employee Transfer discussed in Note 18, we did not sponsor a
unit-based compensation plan. Upon completion of the Employee Transfer, we adopted this amended guidance effective
January 1, 2016 on a prospective basis, which did not have a material impact on our financial position, results of operations or
disclosures. Please refer to Note 24 for a discussion of our long-term incentive plan.
Leases
In February 2016, the FASB issued amended guidance that requires lessees to recognize the assets and liabilities that arise from
most leases on the balance sheet. For lessors, this amended guidance modifies the classification criteria and the accounting for
sales-type and direct financing leases. The changes are effective for annual and interim periods beginning after
December 15, 2018, and amendments should be applied using a modified retrospective approach for leases that exist or are
entered into after the beginning of the earliest comparative period in the financial statements, with the option to use certain
expedients. We currently expect to adopt these provisions on January 1, 2019. We are currently assessing the impact of this
amended guidance on our financial position, results of operations and disclosures and plan to provide additional information
about the expected financial impact at a future date. See Note 15 for commitments under our current operating lease
arrangements.
Financial Instruments
In January 2016, the FASB issued new guidance that addresses certain aspects of recognition, measurement, presentation and
disclosure of financial instruments. The changes are effective for annual and interim periods beginning after
December 15, 2017, and amendments should be applied by means of a cumulative-effect adjustment to the balance sheet as of
the beginning of the fiscal year of adoption. We will adopt these provisions January 1, 2018, and we do not expect the guidance
to have a material impact on our financial position, results of operations or disclosures.
Inventory
In July 2015, the FASB issued amended guidance that requires inventory to be measured at the lower of cost or net realizable
value. The changes are effective for annual and interim periods beginning after December 15, 2016, and must be applied
prospectively after the date of adoption. We adopted these provisions prospectively on January 1, 2017, and such adoption did
not have an impact on our financial position, results of operations or disclosures.
Debt Issuance Costs
In April 2015, the FASB issued amended guidance for the presentation of debt issuance costs. Under the amended guidance,
debt issuance costs will be presented on the balance sheet as a deduction from the carrying value of the associated debt liability.
In August 2015, the FASB issued amended guidance that would allow debt issuance costs related to line-of-credit agreements to
continue to be presented as an asset on the balance sheet. The changes are effective for annual and interim periods beginning
after December 15, 2015, and retrospective application is required. On January 1, 2016, we retrospectively adopted this
guidance. As a result, we reclassified $23.7 million of deferred debt issuance costs from “Other long-term assets, net” to
“Long-term debt” on the consolidated balance sheet as of December 31, 2015. Unamortized debt issuance costs of
$21.2 million are recorded as a reduction to “Long-term debt” on the consolidated balance sheet as of December 31, 2016.
Revenue Recognition
In May 2014, the FASB and the International Accounting Standards Board jointly issued a comprehensive new revenue
recognition standard. In August 2015, the FASB deferred the effective date by one year. The standard is now effective for public
entities for annual and interim periods beginning after December 15, 2017, using one of two retrospective transition methods.
Early adoption is permitted, but not before the original effective date. The FASB has subsequently issued several updates that
amend and/or clarify the new revenue recognition standard. Full implementation of the new revenue recognition standard will
be completed by the end of 2017. Based on our analysis completed to date, we do not believe the standard will significantly
impact the amount or timing of revenues recognized under the vast majority of our revenue contracts. We currently expect to
adopt the new guidance using the modified retrospective approach, under which the cumulative effect of initially applying the
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
new guidance is recognized as an adjustment to the opening balance of retained earnings, in the first quarter of 2018. We are
continuing to evaluate the impact of this new guidance on our financial position, results of operations and disclosures.
4. ACQUISITIONS
Martin Terminal Acquisition. On December 21, 2016, we acquired crude oil and refined product storage assets in Corpus
Christi, TX for $95.7 million, including $2.1 million of capital expenditure reimbursements, from Martin Operating Partnership
L.P. (the Martin Terminal Acquisition). The assets acquired are in our storage segment and include 900,000 barrels of crude oil
storage capacity, 250,000 barrels of refined product storage capacity and exclusive use of the Port of Corpus Christi’s new
crude oil dock.
Linden Acquisition. On January 2, 2015, we acquired full ownership of Linden, which owns a refined products terminal in
Linden, NJ with 4.3 million barrels of storage capacity. Linden is located on a 44-acre facility that provides deep-water
terminalling capabilities in the New York Harbor and primarily stores petroleum products, including gasoline, jet fuel and fuel
oils. Prior to the Linden Acquisition, Linden operated as a joint venture between us and Linden Holding Corp., with each party
owning 50%.
In connection with the Linden Acquisition, we ceased applying the equity method of accounting and consolidated Linden,
which is included in our storage segment. The consolidated statements of income include the results of operations for Linden
commencing on January 2, 2015. On the acquisition date, we remeasured our existing 50% equity investment in Linden to its
fair value of $128.0 million and we recognized a gain of $56.3 million in “Other (expense) income, net” in the consolidated
statements of income for the year ended December 31, 2015. We estimated the fair value using a market approach and an
income approach. The market approach estimates the enterprise value based on an earnings multiple. The income approach
calculates fair value by discounting the estimated net cash flows. We funded the acquisition with borrowings under our
revolving credit agreement. The acquisition complements our existing storage operations, and having sole ownership of Linden
strengthens our presence in the New York Harbor and the East Coast market.
We accounted for the Linden Acquisition using the acquisition method. The purchase price has been allocated based on the
estimated fair values of the individual assets acquired and liabilities assumed at the date of the acquisition.
The final purchase price allocation was as follows (in thousands of dollars):
Cash paid for the Linden Acquisition
Fair value of liabilities assumed
Consideration
Acquisition date fair value of previously held equity interest
Total
Current assets (a)
Property, plant and equipment
Goodwill
Intangible assets (b)
Other long-term assets
Purchase price allocation
$
$
$
$
142,500
22,865
165,365
128,000
293,365
9,513
134,484
79,208
70,050
110
293,365
(a) Current assets include a receivable of $7.8 million related to a pre-acquisition insurance claim, for which proceeds were received in
2015.
(b) Intangible assets primarily consist of customer contracts and relationships and are being amortized over 10 years.
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5. DISPOSITIONS
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Terminal Dispositions
In January 2015, we sold our terminal in Alamogordo, NM with storage capacity of 0.1 million barrels for proceeds of $1.1
million. In 2014, we divested our terminals in Mobile, AL, Wilmington, NC and Dumfries, VA and our 75% interest in our
facility in Mersin, Turkey (the Turkey Sale). We recognized a gain of $3.7 million on the Turkey Sale for the year ended
December 31, 2014. We presented the results of operations for these facilities as discontinued operations.
2014 Asphalt Sale
On February 26, 2014, we sold our remaining 50% ownership interest in NuStar Asphalt LLC to Lindsay Goldberg LLC, a
private investment firm (the 2014 Asphalt Sale). Effective February 27, 2014, NuStar Asphalt LLC changed its name to Axeon
Specialty Products LLC (Axeon). As a result of the 2014 Asphalt Sale, we ceased applying the equity method of
accounting. Therefore, the results of our investment in Axeon were reported in “Equity in earnings of joint ventures” in the
consolidated statements of income through February 25, 2014. Upon completion of the 2014 Asphalt Sale, the parties agreed to:
(i) convert the $250.0 million unsecured revolving credit facility provided by us to Axeon into a $190.0 million term loan (the
Axeon Term Loan); (ii) terminate the terminal services agreements with respect to our terminals in Rosario, NM, Catoosa, OK
and Houston, TX; (iii) amend the terminal services agreements for our terminals in Baltimore, MD and Jacksonville, FL; and
(iv) transfer ownership of both the Wilmington, NC and Dumfries, VA terminals to Axeon. We ceased reporting transactions
between us and Axeon as related party transactions in our consolidated financial statements on February 26, 2014. See Note 8
for additional information on the Axeon Term Loan.
6. ALLOWANCE FOR DOUBTFUL ACCOUNTS
The changes in the allowance for doubtful accounts consisted of the following:
Balance as of beginning of year
Increase in allowance, net
Accounts charged against the allowance
Balance as of end of year
7. INVENTORIES
Inventories consisted of the following:
Year Ended December 31,
2016
2015
2014
(Thousands of Dollars)
$
$
8,473
24
(741)
7,756
$
$
7,808
965
(300)
8,473
$
$
1,224
7,649
(1,065)
7,808
December 31,
2016
2015
Crude oil and refined petroleum products
Materials and supplies
Total
$
$
$
(Thousands of Dollars)
28,044
9,901
37,945
$
30,154
8,595
38,749
We purchase crude oil and refined petroleum products for resale. Our refined petroleum products consist of intermediates,
gasoline, distillates and other petroleum products. Materials and supplies mainly consist of blending and additive chemicals and
maintenance materials used in our pipeline and storage segments.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
8. OTHER CURRENT ASSETS
Other current assets consisted of the following:
December 31,
2016
2015
Axeon Term Loan
Prepaid expenses
Derivative assets
Other
Other current assets
$
$
$
(Thousands of Dollars)
110,000
14,894
155
7,637
132,686
$
—
16,331
11,402
3,443
31,176
Axeon Term Loan. In December 2016, Lindsay Goldberg LLC informed us that they entered into an agreement to sell Axeon’s
retail asphalt sales and distribution business (the Axeon Sale), and we entered into an agreement with Axeon (the Axeon Letter
Agreement) to settle and terminate the Axeon Term Loan with a $110.0 million payment to us upon closing of the Axeon Sale.
As a result of the Axeon Letter Agreement and our review of Axeon’s financial statements, we determined it was probable that
we would not receive all contractual amounts due under the Axeon Term Loan. Therefore, we recorded a charge of $58.7
million, included in “Other (expense) income, net” in the consolidated statements of income, to reduce the carrying amount of
the Axeon Term Loan to $110.0 million and reclassified the Axeon Term Loan from “Other long-term assets, net” to “Other
current assets” on the consolidated balance sheet as of December 31, 2016. The Axeon Sale closed on February 22, 2017. In
conjunction with the closing, we received the $110.0 million payment in accordance with the Axeon Letter Agreement, the
Axeon Term Loan terminated and we are no longer required to provide ongoing credit support to Axeon. We were not
obligated to perform under any of the guarantees or letters of credit provided prior to the closing of the Axeon Sale. We are in
the process of terminating certain guarantees that we previously issued on Axeon’s behalf that remain outstanding after the
Axeon Sale, but these guarantees are supported by a letter of credit provided to us in an amount equal to those remaining
guarantees, thereby reducing our exposure to zero. In addition, in connection with the closing of the Axeon Sale, the terminal
storage agreements that Axeon has with our Jacksonville, Florida and Baltimore, Maryland terminal facilities were amended to
increase the storage fees.
The recently terminated Axeon Term Loan included scheduled repayments in 2014 and 2015, which were subject to Axeon
meeting certain restrictive requirements contained in its third-party asset-based revolving credit facility. In 2015 and 2014,
those requirements prohibited Axeon from making the two scheduled principal payments, which, under the provisions of the
Axeon Term Loan, increased the interest rate payable by Axeon. The Axeon Term Loan was scheduled to be repaid no later
than September 28, 2019. Prior to the closing of the Axeon Sale, we reviewed the financial information of Axeon monthly for
possible credit loss indicators. We recognized interest income associated with the Axeon Term Loan ratably over the term of
the loan in “Interest expense, net” on the consolidated statements of income.
Under our agreements with Axeon, we also provided credit support, such as guarantees, letters of credit and cash collateral, as
applicable, of up to $125.0 million to Axeon. As of December 31, 2016, we had provided guarantees for Axeon with an
aggregate maximum potential exposure of $54.1 million, plus one guarantee to suppliers that did not specify a maximum
amount. As of December 31, 2016, we had also provided $16.7 million in letters of credit on behalf of Axeon. Please refer to
Note 16 for a discussion of the guarantees.
As of December 31, 2015, the carrying amount of the Axeon Term Loan was $170.4 million, consisting of the following: (i) the
outstanding principal amount from the Axeon Term Loan of $190.0 million; (ii) plus the fair value of guarantees of $1.7
million; (iii) less equity losses from our investment in Axeon of $21.3 million incurred prior to the 2014 sale of our remaining
ownership interest in Axeon and after the carrying value of our equity investment in Axeon was reduced to zero. The carrying
value of the Axeon Term Loan as of December 31, 2015 was included in “Other long-term assets, net” on the consolidated
balance sheet.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
9. PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment, at cost, consisted of the following:
Estimated Useful
Lives
December 31,
2016
2015
Land
Land and leasehold improvements
Buildings
Pipelines, storage and terminals
Rights-of-way
Construction in progress
Total
Less accumulated depreciation and amortization
Property, plant and equipment, net
(Years)
-
-
-
-
-
-
40
40
40
40
5
15
20
20
$
$
$
(Thousands of Dollars)
138,224
187,930
144,773
4,647,718
202,311
114,322
5,435,278
(1,712,995)
3,722,283
140,292
186,848
137,269
4,399,378
194,055
151,318
5,209,160
(1,525,589)
3,683,571
$
Capitalized interest costs added to property, plant and equipment totaled $3.4 million, $5.5 million and $5.7 million for the
years ended December 31, 2016, 2015 and 2014, respectively. Depreciation and amortization expense for property, plant and
equipment totaled $200.7 million, $192.3 million and $177.3 million for the years ended December 31, 2016, 2015 and 2014,
respectively, which includes depreciation expense included in “Income (loss) from discontinued operations, net of tax” on the
consolidated statements of income.
10. INTANGIBLE ASSETS AND OTHER LONG-TERM ASSETS
Intangible Assets
Intangible assets are recorded at cost and are amortized on a straight-line basis over 10 to 47 years. Intangible assets consisted
of the following:
December 31, 2016
December 31, 2015
Cost
Accumulated
Amortization
Cost
Accumulated
Amortization
Customer relationships
Other
Total
$
$
166,950
2,359
169,309
$
$
(Thousands of Dollars)
(41,582) $
(644)
(42,226) $
196,616
2,359
198,975
$
$
(86,370)
(594)
(86,964)
All of our intangible assets are subject to amortization. Amortization expense for intangible assets was $13.9 million, $16.7
million and $12.6 million for the years ended December 31, 2016, 2015 and 2014, respectively. The estimated aggregate
amortization expense is $16.7 million for each of the years 2017 through 2021.
Other Long-Term Assets, Net
Other long-term assets, net consisted of the following:
December 31,
2016
2015
Axeon Term Loan (a)
Amount remaining in trust for the GoZone Bonds (a)
Ammonia pipeline linefill and tank heel inventory
Other
Other long-term assets, net
$
$
(a) See Note 8 for discussion on the Axeon Term Loan and Note 13 for discussion of the GoZone Bonds.
77
(Thousands of Dollars)
— $
42,359
34,377
28,572
105,308
$
170,352
54,822
35,178
36,245
296,597
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11. GOODWILL
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Changes in the carrying amount of goodwill by segment were as follows:
Balances as of January 1, 2015:
Goodwill
Accumulated impairment losses
Net goodwill
Pipeline
Storage
Fuels
Marketing
Total
(Thousands of Dollars)
$
306,207
$
—
306,207
$
612,012
(331,913)
280,099
$
53,255
(22,132)
31,123
971,474
(354,045)
617,429
Activity for the year ended December 31, 2015:
Linden Acquisition final purchase price allocation
—
79,208
—
79,208
Balances as of December 31, 2015 and 2016:
Goodwill
Accumulated impairment losses
Net goodwill
12. ACCRUED LIABILITIES
Accrued liabilities consisted of the following:
Derivative liabilities
Employee wages and benefit costs
Unearned income
Other
Accrued liabilities
13. DEBT
Long-term debt consisted of the following:
Revolving Credit Agreement
4.75% senior notes
6.75% senior notes
4.80% senior notes
7.65% senior notes
7.625% subordinated notes
GoZone Bonds
Receivables Financing Agreement
Net fair value adjustments, unamortized discounts and unamortized
debt issuance costs
Total long-term debt
78
306,207
—
$
306,207
$
691,220
(331,913)
359,307
$
53,255
(22,132)
31,123
$
1,050,682
(354,045)
696,637
December 31,
2016
2015
(Thousands of Dollars)
$
$
5,052
30,807
14,355
10,271
60,485
$
$
121
31,143
14,290
9,640
55,194
December 31,
Maturity
2016
2015
(Thousands of Dollars)
2019
2022
2021
2020
2018
2043
2038 thru 2041
2018
N/A
$
838,992
$
250,000
300,000
450,000
350,000
402,500
365,440
58,400
(968)
3,014,364
$
882,664
250,000
300,000
450,000
350,000
402,500
365,440
53,500
1,508
$
3,055,612
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The long-term debt repayments are due as follows (in thousands):
2017
2018
2019
2020
2021
Thereafter
Total repayments
Net fair value adjustments, unamortized discounts and unamortized debt issuance costs
Total long-term debt
$
$
—
408,400
838,992
450,000
300,000
1,017,940
3,015,332
(968)
3,014,364
Interest payments totaled $146.1 million, $138.9 million and $135.0 million for the years ended December 31, 2016, 2015 and
2014, respectively.
Revolving Credit Agreement
NuStar Logistics is party to a $1.5 billion five-year revolving credit agreement (the Revolving Credit Agreement), which
matures on October 29, 2019. The Revolving Credit Agreement includes an option allowing NuStar Logistics to request an
aggregate increase in the commitments from the lenders of up to $250.0 million (after which increase the aggregate
commitment from all lenders shall not exceed $1.75 billion). The Revolving Credit Agreement also includes the ability to
borrow up to the equivalent of $250.0 million in Euros and up to the equivalent of $250.0 million in British Pounds Sterling.
Obligations under the Revolving Credit Agreement are guaranteed by NuStar Energy and NuPOP.
The Revolving Credit Agreement bears interest, at our option, based on an alternative base rate, a LIBOR-based rate or a
EURIBOR-based rate. The interest rate on the Revolving Credit Agreement is subject to adjustment if our debt rating is
downgraded (or upgraded) by certain credit rating agencies. As of December 31, 2016, our weighted-average interest rate was
2.5%. During the year ended December 31, 2016, the weighted-average interest rate related to borrowings under the Revolving
Credit Agreement was 2.3%.
The Revolving Credit Agreement contains customary restrictive covenants, such as limitations on indebtedness, liens, mergers,
asset transfers and certain investing activities. In addition, the Revolving Credit Agreement requires us to maintain, as of the
end of each rolling period of four consecutive fiscal quarters, a consolidated debt coverage ratio (consolidated debt to
consolidated EBITDA, each as defined in the Revolving Credit Agreement) not to exceed 5.00-to-1.00. If we consummate an
acquisition for an aggregate net consideration of at least $50.0 million, the maximum consolidated debt coverage ratio will
increase to 5.50-to-1.00 for two rolling periods. As of December 31, 2016, our consolidated debt coverage ratio could not
exceed 5.50-to-1.00, as a result of the Martin Terminal Acquisition in December 2016. The requirement not to exceed a
maximum consolidated debt coverage ratio may limit the amount we can borrow under the Revolving Credit Agreement to an
amount less than the total amount available for borrowing. As of December 31, 2016, we had $645.2 million available for
borrowing.
Letters of credit issued under the Revolving Credit Agreement totaled $15.8 million as of December 31, 2016. Letters of credit
are limited to $750.0 million (including up to the equivalent of $25.0 million in Euros and up to the equivalent of $25.0 million
in British Pounds Sterling) and also may restrict the amount we can borrow under the Revolving Credit Agreement.
Notes
NuStar Logistics Senior Notes. Interest is payable semi-annually in arrears for the $250.0 million of 4.75% senior notes, $300.0
million of 6.75% senior notes, $450.0 million of 4.80% senior notes and $350.0 million of 7.65% senior notes (collectively, the
NuStar Logistics Senior Notes). The interest rate payable on the 7.65% senior notes is subject to adjustment if our debt rating is
downgraded (or upgraded) by certain credit rating agencies and is at 8.2% as of December 31, 2016. The NuStar Logistics
Senior Notes do not have sinking fund requirements. These notes rank equally with existing senior unsecured indebtedness of
NuStar Logistics and contain restrictions on NuStar Logistics’ ability to incur additional secured indebtedness unless the same
security is also provided for the benefit of holders of the NuStar Logistics Senior Notes. In addition, the NuStar Logistics
Senior Notes limit NuStar Logistics’ ability to incur indebtedness secured by certain liens and to engage in certain sale-
leaseback transactions. At the option of NuStar Logistics, the NuStar Logistics Senior Notes may be redeemed in whole or in
part at any time at a redemption price, which includes a make-whole premium, plus accrued and unpaid interest to the
redemption date. The NuStar Logistics Senior Notes are fully and unconditionally guaranteed by NuStar Energy and NuPOP.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
NuStar Logistics 7.625% Fixed-to-Floating Rate Subordinated Notes. NuStar Logistics’ $402.5 million of 7.625% fixed-to-
floating rate subordinated notes are due January 15, 2043 (the Subordinated Notes). The Subordinated Notes are fully and
unconditionally guaranteed on an unsecured and subordinated basis by NuStar Energy and NuPOP. The Subordinated Notes
bear interest at a fixed annual rate of 7.625%, payable quarterly in arrears beginning on April 15, 2013 and ending on
January 15, 2018. Thereafter, the Subordinated Notes will bear interest at an annual rate equal to the sum of the three-month
LIBOR rate for the related quarterly interest period, plus 6.734% payable quarterly, commencing April 15, 2018, unless
payment is deferred in accordance with the terms of the notes. NuStar Logistics may elect to defer interest payments on the
Subordinated Notes on one or more occasions for up to five consecutive years. Deferred interest will accumulate additional
interest at a rate equal to the interest rate then applicable to the Subordinated Notes until paid. If NuStar Logistics elects to
defer interest payments, NuStar Energy cannot declare or make cash distributions to its unitholders during the period that
interest payments are deferred.
The Subordinated Notes do not have sinking fund requirements and are subordinated to existing senior unsecured indebtedness
of NuStar Logistics and NuPOP. The Subordinated Notes do not contain restrictions on NuStar Logistics’ ability to incur
additional indebtedness, including debt that ranks senior in priority of payment to the notes. In addition, the Subordinated Notes
do not limit NuStar Logistics’ ability to incur indebtedness secured by liens or to engage in certain sale-leaseback transactions.
At the option of NuStar Logistics, the Subordinated Notes may be redeemed in whole or in part at any time at a redemption
price, which may include a make-whole premium, plus accrued and unpaid interest to the redemption date.
Gulf Opportunity Zone Revenue Bonds
In 2008, 2010 and 2011, the Parish of St. James, Louisiana issued Revenue Bonds Series 2008, Series 2010, Series 2010A,
Series 2010B and Series 2011 associated with our St. James terminal expansions pursuant to the Gulf Opportunity Zone Act of
2005 for an aggregate $365.4 million (collectively, the GoZone Bonds). The interest rates on these bonds are based on a weekly
tax-exempt bond market interest rate, and interest is paid monthly. Following the issuances, the proceeds were deposited with a
trustee and are disbursed to us upon our request for reimbursement of expenditures related to our St. James terminal
expansions. We include the amount remaining in the trust in “Other long-term assets, net,” and we include the amount of bonds
issued in “Long-term debt” in our consolidated balance sheets. For the years ended December 31, 2016 and 2015, the amount
received from the trustee totaled $12.5 million and $17.5 million, respectively.
NuStar Logistics is solely obligated to service the principal and interest payments associated with the GoZone Bonds. Letters of
credit were issued by various individual banks on our behalf to guarantee the payment of interest and principal on the bonds.
All letters of credit rank equally with existing senior unsecured indebtedness of NuStar Logistics. Obligations under the letters
of credit issued are guaranteed by NuStar Energy and NuPOP. The letters of credit issued by individual banks do not restrict the
amount we can borrow under the Revolving Credit Agreement.
The following table summarizes the GoZone Bonds outstanding as of December 31, 2016:
Date Issued
Maturity Date
Amount
Outstanding
Amount of
Letter of
Credit
Amount
Received from
Trustee
Amount
Remaining in
Trust (a)
Weighted-
Average
Interest Rate (b)
(Thousands of Dollars)
June 26, 2008
July 15, 2010
June 1, 2038
July 1, 2040
$
55,440
$
56,169
$
55,440
$
100,000
101,315
100,000
October 7, 2010
October 1, 2040
December 29, 2010
December 1, 2040
August 29, 2011
August 1, 2041
50,000
85,000
75,000
50,658
86,118
75,986
43,741
49,782
75,000
—
—
6,518
35,841
—
Total
$
365,440
$
370,246
$
323,963
$
42,359
0.7%
0.7%
0.7%
0.7%
0.7%
(a) Amount remaining in trust includes accrued interest.
(b) For the year ended December 31, 2016, our weighted-average interest rate on borrowings was 0.4%.
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Receivables Financing Agreement
NuStar Energy and NuStar Finance LLC (NuStar Finance), a special purpose entity and wholly owned subsidiary of NuStar
Logistics, are parties to a $125.0 million receivables financing agreement with third-party lenders (the Receivables Financing
Agreement) and agreements with certain of NuStar Energy’s wholly owned subsidiaries (collectively with the Receivables
Financing Agreement, the Securitization Program). Under the Securitization Program, certain of NuStar Energy’s wholly
owned subsidiaries, NuStar Logistics, NuPOP, NuStar Energy Services, Inc. and NuStar Supply & Trading LLC (collectively,
the Originators), sell their accounts receivable to NuStar Finance on an ongoing basis, and NuStar Finance provides the newly
acquired accounts receivable as collateral for its revolving borrowings under the Receivables Financing Agreement. NuStar
Energy provides a performance guarantee in connection with the Securitization Program. The maximum amount available for
borrowing by NuStar Finance under the Receivables Financing Agreement is $125.0 million, with an option for NuStar Finance
to request an increase of up to $75.0 million from the lenders (for aggregate total borrowings not to exceed $200.0 million).
The amount available for borrowing is based on the availability of eligible receivables and other customary factors and
conditions. The Securitization Program contains various customary affirmative and negative covenants and default,
indemnification and termination provisions, and the Receivables Financing Agreement provides for acceleration of amounts
owed upon the occurrence of certain specified events.
Borrowings by NuStar Finance under the Receivables Financing Agreement bear interest at either the applicable commercial
paper rate or the applicable bank rate, each as defined under the Receivables Financing Agreement. The Securitization Program
has an initial termination date of June 15, 2018, with the option to renew for additional 364-day periods thereafter. As of
December 31, 2016 and 2015, $104.5 million and $97.9 million of our accounts receivable were included in the Securitization
Program, respectively. The weighted average interest rate related to outstanding borrowings under the Securitization Program
during the year ended December 31, 2016 was 1.4%.
NuStar Finance’s sole activity consists of purchasing such receivables and providing them as collateral under the Securitization
Program. NuStar Finance is a separate legal entity and the assets of NuStar Finance, including these accounts receivable, are
not available to satisfy the claims of creditors of NuStar Energy, the Originators or their affiliates.
Short-Term Lines of Credit
NuStar Logistics is party to two short-term line of credit agreements with an aggregate uncommitted borrowing capacity of up
to $75.0 million, which allow us to better manage fluctuations in our daily cash requirements and minimize our excess cash
balances. The interest rate and maturity vary and are determined at the time of borrowing. We had $54.0 million outstanding
under these lines of credit as of December 31, 2016. Obligations under these short-term line of credit agreements are
guaranteed by NuStar Energy. The weighted-average interest rate related to outstanding borrowings under our short-term lines
of credit during the year ended December 31, 2016 was 2.0%.
14. HEALTH, SAFETY AND ENVIRONMENTAL MATTERS
Our operations are subject to extensive federal, state and local environmental laws and regulations, in the U.S. and in the other
countries in which we operate, including those relating to the discharge of materials into the environment, waste management,
remediation, the characteristics and composition of fuels and pollution prevention measures, among others. Our operations are
also subject to extensive federal, state and local health and safety laws and regulations, including those relating to worker and
pipeline safety, pipeline integrity and operator qualifications. The principal environmental and safety risks associated with our
operations relate to unauthorized or unpermitted emissions into the air, unauthorized releases into soil, surface water or
groundwater, personal injury and property damage. Compliance with these environmental, health and safety laws, regulations
and related permits increases our capital expenditures and operating expenses, and violation of these laws, regulations or
permits could result in significant civil and criminal liabilities, injunctions or other penalties.
Most of our pipelines are subject to federal regulation by one or more of the following governmental agencies: the Federal
Energy Regulatory Commission (the FERC), the Surface Transportation Board (the STB), the Department of Transportation
(DOT), the Environmental Protection Agency (EPA) and the Department of Homeland Security. Additionally, the operations
and integrity of the pipelines are subject to the respective state jurisdictions along the routes of the systems.
We have adopted policies, practices and procedures to address pollution control, pipeline integrity, operator qualifications,
public relations and education, process safety management, risk management planning, hazard communication, emergency
response planning, community right-to-know, occupational health and the handling, storage, use and disposal of hazardous
materials. Our policies are designed to comply with applicable federal, state and local regulations and to prevent material
environmental or other damage, to ensure the safety of our pipelines, our employees, the public and the environment and to
limit the financial liability that could result from such events. Future governmental action and regulatory initiatives could
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
necessitate changes to expected operating permits and procedures, additional remedial actions or increased capital expenditures
and operating costs. Risks of additional costs and liabilities are inherent within the industry, and there can be no assurances that
significant costs and liabilities will not be incurred in the future.
Environmental and safety exposures and liabilities are difficult to assess and estimate due to unknown factors such as the
timing and extent of remediation, the determination of our liability in proportion to other parties, improvements in cleanup
technologies and the extent to which environmental and safety laws and regulations may change in the future. Although
environmental and safety costs may have a significant impact on the results of operations for any single period, we believe that
such costs will not have a material adverse effect on our financial position.
The balance of and changes in the accruals for environmental matters were as follows:
Balance as of the beginning of year
Additions to accrual
Payments
Foreign currency translation
Balance as of the end of year
Year Ended December 31,
2016
2015
(Thousands of Dollars)
$
$
7,667
$
870
(3,302)
(115)
5,120
$
6,598
3,685
(2,574)
(42)
7,667
Accruals for environmental matters are included in the consolidated balance sheets as follows:
Accrued liabilities
Other long-term liabilities
Accruals for environmental matters
15. COMMITMENTS AND CONTINGENCIES
December 31,
2016
2015
(Thousands of Dollars)
$
$
3,281
1,839
5,120
$
$
4,350
3,317
7,667
Contingencies
We have contingent liabilities resulting from various litigation, claims and commitments. We record accruals for loss
contingencies when losses are considered probable and can be reasonably estimated. Legal fees associated with defending the
Partnership in legal matters are expensed as incurred. We have no amount accrued for contingent losses as of December 31,
2016, and $4.8 million accrued for contingent losses as of December 31, 2015. The amount that will ultimately be paid related
to such matters may differ from the recorded accruals, and the timing of such payments is uncertain. In addition, due to the
inherent uncertainty of litigation, there can be no assurance that the resolution of any particular claim or proceeding would not
have a material adverse effect on our results of operations, financial position or liquidity.
Commitments
Lessee Commitments. Future minimum rental payments applicable to all noncancellable operating leases and purchase
obligations as of December 31, 2016 are as follows:
2017
2018
2019
2020
2021
There-
after
Total
Payments Due by Period
(Thousands of Dollars)
Operating leases
Purchase obligations
$
31,041
$
29,316
$
22,718
$
10,861
$
5,314
$
56,461
$
155,711
4,088
2,630
1,449
42
—
—
8,209
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Rental expense for all operating leases totaled $37.0 million, $39.7 million and $46.1 million for the years ended December 31,
2016, 2015 and 2014, respectively. Our operating leases consist primarily of the following:
•
•
a ten-year lease for tugs and barges utilized at our St. Eustatius facility for bunker fuel sales, with two five-year
renewal options; and
land leases at various terminal facilities, with original terms ranging from 10 to 100 years.
Lessor Commitments. We have entered into certain revenue arrangements where we are considered to be the lessor in
accordance with GAAP. Under these arrangements we lease certain of our storage tanks in exchange for a fixed fee subject to
an annual consumer price index adjustment. The arrangements commenced on January 1, 2017, and have initial terms of ten
years with successive ten-year automatic renewal terms. Future minimum revenues we expect to receive under these lease
arrangements as of December 31, 2016 total $391.3 million, which we will recognize ratably over the ten-year term.
16. FAIR VALUE MEASUREMENTS
We segregate the inputs used in measuring fair value into three levels: Level 1, defined as observable inputs such as quoted
prices for identical assets or liabilities in active markets; Level 2, defined as inputs other than quoted prices in active markets
that are either directly or indirectly observable, such as quoted prices for similar assets or liabilities in active markets or quoted
prices for identical assets or liabilities in markets that are not active; and Level 3, defined as unobservable inputs for which
little or no market data exists. We consider counterparty credit risk and our own credit risk in the determination of all estimated
fair values.
Recurring Fair Value Measurements
The following assets and liabilities are measured at fair value on a recurring basis:
December 31, 2016
Level 1
Level 2
Level 3
Total
(Thousands of Dollars)
Assets:
Other current assets:
Product imbalances
Commodity derivatives
Other long-term assets, net:
Interest rate swaps
Total
Liabilities:
Accrued liabilities:
Product imbalances
Commodity derivatives
Other long-term liabilities:
Guarantee liability
Interest rate swaps
Total
1,551
$
—
—
— $
155
1,314
— $
—
—
1,551
$
1,469
$
— $
1,551
155
1,314
3,020
(1,577) $
(4,887)
—
—
(6,464) $
— $
(165)
—
(2,632)
(2,797) $
— $
—
(1,577)
(5,052)
(1,230)
—
(1,230) $
(1,230)
(2,632)
(10,491)
$
$
$
$
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Assets:
Other current assets:
Product imbalances
Commodity derivatives
Other long-term assets, net:
Interest rate swaps
Total
Liabilities:
Accrued liabilities:
Product imbalances
Commodity derivatives
Other long-term liabilities:
Guarantee liability
Interest rate swaps
Total
December 31, 2015
Level 1
Level 2
Level 3
Total
(Thousands of Dollars)
$
$
$
$
179
$
11,325
— $
77
—
2,755
— $
—
—
11,504
$
2,832
$
— $
(419) $
—
—
—
(419) $
— $
(120)
—
(1,452)
(1,572) $
— $
—
(1,697)
—
(1,697) $
179
11,402
2,755
14,336
(419)
(120)
(1,697)
(1,452)
(3,688)
Product Imbalances. Since we value our assets and liabilities related to product imbalances using quoted market prices in active
markets as of the reporting date, we include these product imbalances in Level 1 of the fair value hierarchy.
Commodity Derivatives. We base the fair value of certain of our commodity derivative instruments on quoted prices on an
exchange; accordingly, we include these items in Level 1 of the fair value hierarchy. We also have derivative instruments for
which we determine fair value using industry pricing services and other observable inputs, such as quoted prices on an
exchange for similar derivative instruments, and we include these derivative instruments in Level 2 of the fair value hierarchy.
See Note 17 for a discussion of our derivative instruments.
Interest Rate Swaps. Because we estimate the fair value of our forward-starting interest rate swaps using discounted cash flows,
which use observable inputs such as time to maturity and market interest rates, we include these interest rate swaps in Level 2
of the fair value hierarchy.
Guarantees. As of December 31, 2016 and 2015, we recorded a liability of $1.2 million and $1.7 million, respectively,
representing the fair value of guarantees we have issued on behalf of Axeon. We estimated the fair value considering the
probability of default by Axeon and an estimate of the amount we would be obligated to pay under the guarantees at the time of
default. We calculated the fair value based on the guarantees outstanding as of December 31, 2016 and 2015, totaling $54.1
million and $71.9 million, respectively, and one guarantee that did not specify a maximum amount as of December 31, 2016.
As of December 31, 2015, we provided two guarantees that did not specify a maximum amount. We provided guarantees for
commodity purchases, lease obligations and certain utilities for Axeon. Our estimate of the fair value was based on significant
inputs not observable in the market and thus fell within Level 3 of the fair value hierarchy. After the Axeon Sale closed on
February 22, 2017, we are no longer obligated to provide ongoing credit support, including guarantees, on behalf of Axeon. We
are in the process of terminating certain guarantees that we previously issued on Axeon’s behalf that remain outstanding after
the Axeon Sale, but these guarantees are supported by a letter of credit provided to us in an amount equal to those remaining
guarantees, thereby reducing our exposure to zero. See Note 8 for additional information on the Axeon Term Loan.
The following table summarizes the activity in our Level 3 liabilities:
Beginning balance
Adjustment to guarantee liability
Ending balance
84
Year Ended
December 31, 2016
(Thousands of Dollars)
$
$
1,697
(467)
1,230
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Fair Value of Financial Instruments
We recognize cash equivalents, receivables, payables and debt in our consolidated balance sheets at their carrying amounts. The
fair values of these financial instruments, except for the Axeon Term Loan and long-term debt, approximate their carrying
amounts.
The estimated fair values and carrying amounts of the long-term debt and the Axeon Term Loan were as follows:
Long-term debt
Axeon Term Loan
December 31, 2016
December 31, 2015
Fair Value
Carrying Amount
Fair Value
Carrying Amount
(Thousands of Dollars)
$
$
3,084,762
110,000
$
$
3,014,364
110,000
$
$
2,929,438
172,123
$
$
3,055,612
170,352
We estimated the fair value of our publicly traded senior notes based upon quoted prices in active markets; therefore, we
determined that the fair value of our publicly traded senior notes falls in Level 1 of the fair value hierarchy. For our other debt,
for which a quoted market price is not available, we estimated the fair value using a discounted cash flow analysis using current
incremental borrowing rates for similar types of borrowing arrangements and determined that the fair value falls in Level 2 of
the fair value hierarchy.
Since we expected to settle and terminate the Axeon Term Loan upon closing of the Axeon Sale in 2017, we reclassified the
Axeon Term Loan into “Other current assets” on the consolidated balance sheet as of December 31, 2016. We also determined
that the fair value of the Axeon Term Loan approximated its carrying value as of December 31, 2016. See Note 8 for additional
information on the Axeon Term Loan.
As of December 31, 2015, we estimated the fair value of the Axeon Term Loan using discounted cash flows, which used
observable inputs such as time to maturity and market interest rates, and determined that the fair value fell in Level 2 of the fair
value hierarchy. The carrying value of the Axeon Term Loan as of December 31, 2015 was included in “Other long-term assets,
net” on the consolidated balance sheet.
17. DERIVATIVES AND RISK MANAGEMENT ACTIVITIES
We utilize various derivative instruments to manage our exposure to interest rate risk and commodity price risk. Our risk
management policies and procedures are designed to monitor interest rates, futures and swap positions and over-the-counter
positions, as well as physical volumes, grades, locations and delivery schedules, to help ensure that our hedging activities
address our market risks.
Interest Rate Risk
We are a party to certain interest rate swap agreements to manage our exposure to changes in interest rates, which include
forward-starting interest rate swap agreements related to forecasted debt issuances in 2018 and 2020. We entered into these
swaps during the year ended December 31, 2015, in order to hedge the risk of changes in the interest payments attributable to
changes in the benchmark interest rate during the period from the effective date of the swap to the issuance of the forecasted
debt. Under the terms of the swaps, we pay a fixed rate and receive a rate based on three month USD LIBOR. These swaps
qualified, and we designated them, as cash flow hedges. We record the effective portion of mark-to-market adjustments as a
component of AOCI, and the amount in AOCI will be recognized in “Interest expense, net” as the forecasted interest payments
occur or if the interest payments are probable not to occur. As of December 31, 2016 and 2015, the aggregate notional amount
of forward-starting interest rate swaps totaled $600.0 million.
The remaining fair value amount associated with unwound fixed-to-floating interest rate swap agreements totaled a $21.1
million and $26.3 million gain as of December 31, 2016 and 2015, respectively, and is included in “Long-term debt” on the
consolidated balance sheets. The remaining fair value amount associated with unwound forward-starting interest rate swap
agreements totaled a $20.9 million and a $29.3 million loss as of December 31, 2016 and 2015, respectively, and is included in
AOCI on the consolidated balance sheets. These amounts are amortized ratably over the remaining life of the related debt
instrument into “Interest expense, net” on the consolidated statements of income.
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Commodity Price Risk
We are exposed to market risks related to the volatility of crude oil and refined product prices. In order to reduce the risk of
commodity price fluctuations with respect to our crude oil and refined product inventories and related firm commitments to
purchase and/or sell such inventories, we utilize commodity futures and swap contracts, which qualify and we designate as fair
value hedges. Derivatives that are intended to hedge our commodity price risk, but fail to qualify as fair value or cash flow
hedges, are considered economic hedges, and we record associated gains and losses in net income. Our risk management
committee oversees our trading controls and procedures and certain aspects of commodity and trading risk management. Our
risk management committee also reviews all new commodity and trading risk management strategies in accordance with our
risk management policy, as approved by our board of directors.
The volume of commodity contracts is based on open derivative positions and represents the combined volume of our long and
short open positions on an absolute basis, which totaled 4.7 million barrels and 8.0 million barrels as of December 31, 2016 and
2015, respectively. As of December 31, 2016, we had $1.8 million of margin deposits; we had no margin deposits as of
December 31, 2015.
The fair values of our derivative instruments included in our consolidated balance sheets were as follows:
Asset Derivatives
Liability Derivatives
December 31,
Balance Sheet Location
2016
2015
2016
2015
(Thousands of Dollars)
Derivatives Designated as
Hedging Instruments:
Commodity contracts
Interest rate swaps
Commodity contracts
Interest rate swaps
Total
Derivatives Not Designated
as Hedging Instruments:
Commodity contracts
Commodity contracts
Total
Other current assets
$
— $
1,937
$
— $
Other long-term assets, net
Accrued liabilities
Other long-term liabilities
Other current assets
Accrued liabilities
1,314
144
—
1,458
265
9,128
9,393
2,755
—
—
4,692
—
(3,566)
(2,632)
(6,198)
(23)
—
—
(1,452)
(1,475)
34,016
117
34,133
(110)
(10,758)
(10,868)
(24,528)
(237)
(24,765)
Total Derivatives
$
10,851
$
38,825
$ (17,066) $
(26,240)
Certain of our derivative instruments are eligible for offset in the consolidated balance sheets and subject to master netting
arrangements. Under our master netting arrangements, there is a legally enforceable right to offset amounts, and we intend to
settle such amounts on a net basis. The following are the net amounts presented on the consolidated balance sheets:
Commodity Contracts
Net amounts of assets presented in the consolidated balance sheets
Net amounts of liabilities presented in the consolidated balance sheets
December 31,
2016
2015
(Thousands of Dollars)
$
$
155
$
(5,052) $
11,402
(120)
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
We recognize the impact of our commodity contracts on earnings in “Cost of product sales” on the consolidated income
statements, and that impact was as follows:
Derivatives Designated as Fair Value Hedging Instruments:
(Loss) gain recognized in income on derivative
Gain (loss) recognized in income on hedged item
Gain recognized in income for ineffective portion
Derivatives Not Designated as Hedging Instruments:
Gain recognized in income on derivative
Our interest rate swaps also had the following impact on earnings:
$
$
Year Ended December 31,
2016
2015
2014
(Thousands of Dollars)
(11,254) $
15,295
4,041
$
21,589
(18,047)
3,542
21,951
(21,587)
364
225
$
2,208
$
18,407
Derivatives Designated as Cash Flow Hedging Instruments:
(Loss) gain recognized in other comprehensive (loss) income on
derivative (effective portion)
Loss reclassified from AOCI into interest expense, net
(effective portion)
Year Ended December 31,
2016
2015
2014
(Thousands of Dollars)
$
(2,621) $
1,303
$
—
(8,331)
(9,802)
(10,663)
As of December 31, 2016, we expect to reclassify a loss of $6.6 million to “Interest expense, net” within the next twelve
months associated with unwound forward-starting interest rate swaps.
18. RELATED PARTY TRANSACTIONS
NuStar GP, LLC
GP Services Agreement. Prior to the Employee Transfer discussed in Note 1, our operations were managed by NuStar GP, LLC
under a services agreement effective January 1, 2008 pursuant to which employees of NuStar GP, LLC performed services for
our U.S. operations. Employees of NuStar GP, LLC provided services to us and NuStar GP Holdings; therefore, we reimbursed
NuStar GP, LLC for all employee costs incurred prior to the Employee Transfer, other than the expenses allocated to NuStar GP
Holdings. The following table summarizes information pertaining to our related party transactions:
Revenues
Operating expenses
General and administrative expenses
Interest income
Revenues included in discontinued operations, net of tax
Expenses included in discontinued operations, net of tax
Year Ended December 31,
2016
2015
2014
(Thousands of Dollars)
$
$
$
$
$
$
21,681
10,493
— $
$
$
— $
— $
— $
135,565
66,769
— $
$
$
— $
— $
$
2
929
125,736
66,910
1,055
528
1,680
In conjunction with the Employee Transfer, we entered into an Amended and Restated Services Agreement with NuStar GP,
LLC, effective March 1, 2016 (the Amended GP Services Agreement). The Amended GP Services Agreement provides that we
will furnish administrative services necessary to conduct the business of NuStar GP Holdings. NuStar GP Holdings will
compensate us for these services through an annual fee of $1.0 million, subject to adjustment based on the annual merit
increase percentage applicable to our employees for the most recently completed fiscal year and for changes in level of service.
The Amended GP Services Agreement will terminate on March 1, 2020 and will automatically renew for successive two-year
terms, unless terminated by either party.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Assignment and Assumption Agreement. Also on March 1, 2016 and in connection with the Employee Transfer, we entered into
an Assignment and Assumption Agreement with NuStar GP, LLC (the Assignment Agreement). Under the Assignment
Agreement, NuStar GP, LLC assigned all of its employee benefit plans, programs, contracts, policies, and various of its other
agreements and contracts with certain employees, affiliates and third-party service providers (collectively, the Assigned
Programs) to NuStar Services Co. In addition, NuStar Services Co agreed to assume the sponsorship of and all obligations
relating to the ongoing maintenance and administration of each of the plans and agreements in the Assigned Programs. Certain
of our officers are also officers of NuStar GP Holdings and are considered dual employees of ours and NuStar GP Holdings.
The following table summarizes the related party transactions and changes to amounts reported on our consolidated balance
sheet as a result of the Employee Transfer on March 1, 2016 (thousands of dollars):
Decrease in related party payable:
Current
Long-term
Decrease in related party payable
Changes to our consolidated balance sheet:
Current and long-term assets
Current liabilities
Other long-term liabilities
Limited partner’s equity
Accumulated other comprehensive loss
Changes to our consolidated balance sheet
$
$
$
$
16,014
32,656
48,670
2,154
5,609
34,042
2,664
4,201
48,670
Balance Sheet Items. We had a receivable from related party of $0.3 million as of December 31, 2016, mainly comprised of
service fees and expenses paid on behalf of NuStar GP Holdings. As of December 31, 2015, we had a payable to related party
of $14.8 million, mainly comprised of payroll, employee benefit plan expenses and unit-based compensation prior to the
Employee Transfer, and none as of December 31, 2016. We also had a long-term payable to related party as of
December 31, 2015 of $32.1 million, representing long-term employee benefits prior to the Employee Transfer, and none as of
December 31, 2016.
Non-Compete Agreement. On July 19, 2006, we entered into a non-compete agreement with NuStar GP Holdings, Riverwalk
Logistics, L.P. and NuStar GP, LLC (the Non-Compete Agreement). The Non-Compete Agreement became effective on
December 22, 2006 when NuStar GP Holdings ceased to be subject to the Amended and Restated Omnibus Agreement, dated
March 31, 2006. Under the Non-Compete Agreement, we will have a right of first refusal with respect to the potential
acquisition of assets that relate to the transportation, storage or terminalling of crude oil, feedstocks or refined petroleum
products (including petrochemicals) in the United States and internationally. NuStar GP Holdings will have a right of first
refusal with respect to the potential acquisition of general partner and other equity interests in publicly traded partnerships
under common ownership with the general partner interest. With respect to any other business opportunities, neither the
Partnership nor NuStar GP Holdings are prohibited from engaging in any business, even if the Partnership and NuStar GP
Holdings would have a conflict of interest with respect to such other business opportunity.
Axeon
As a result of the 2014 Asphalt Sale, we ceased reporting transactions between us and Axeon as related party transactions in our
consolidated financial statements on February 26, 2014.
Terminal Service Agreements. We were a party to terminal service agreements with Axeon for our terminals in Wilmington,
NC, Rosario, NM, Catoosa, OK, Houston, TX, Jacksonville, FL, Dumfries, VA, and Baltimore, MD. As a result of the 2014
Asphalt Sale, these terminal service agreements were either amended or terminated.
Services Agreement. NuStar GP, LLC and Axeon were a party to a services agreement, which provided that NuStar GP, LLC
would furnish certain administrative and other operating services necessary to conduct the business of Axeon for an annual fee
totaling $10.0 million, subject to adjustment (the Axeon Services Agreement). The Axeon Services Agreement terminated on
June 30, 2014.
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
19. OTHER (EXPENSE) INCOME
Other (expense) income consisted of the following:
Impairment loss on Axeon Term Loan
Gain associated with Linden Acquisition
Foreign exchange (losses) gains
(Loss) gain from sale or disposition of assets
Other, net
Other (expense) income, net
20. PARTNERS’ EQUITY
Year Ended December 31,
2016
2015
2014
(Thousands of Dollars)
$
$
(58,655) $
—
(660)
(64)
596
(58,783) $
— $
56,277
3,891
1,617
37
61,822
$
—
—
2,057
642
1,800
4,499
Issuance of Preferred Units
In the fourth quarter of 2016, we issued 9,060,000 of our 8.50% Series A Fixed-to-Floating Rate Cumulative Redeemable
Perpetual Preferred Units (the Preferred Units) representing limited partner interests at a price of $25.00 per unit. We used the
net proceeds of $218.4 million from this issuance for general partnership purposes, including the funding of capital
expenditures and repayments of outstanding borrowings under the Revolving Credit Agreement.
Distributions on the Preferred Units are payable out of any legally available funds, accrue and are cumulative from the date of
original issuance of the Preferred Units and are payable on the 15th day of each of March, June, September and December of
each year (beginning on March 15, 2017) to holders of record on the first day of each payment month. The initial distribution
rate on the Preferred Units to, but not including, December 15, 2021 is 8.50% per annum of the $25.00 liquidation preference
per unit (equal to $2.125 per unit per annum). On and after December 15, 2021, distributions on the Preferred Units
accumulate at a percentage of the $25.00 liquidation preference equal to an annual floating rate of the three-month LIBOR plus
a spread of 6.766%. On January 27, 2017, we announced a Preferred Unit distribution of $0.64930556 per unit to be paid on
March 15, 2017 to holders of record as of March 1, 2017 for distributions accumulated from the issuance date up to the
payment date. The Preferred Units rank senior to all of our other classes of equity securities with respect to distribution rights
and rights upon liquidation.
At any time on or after December 15, 2021, we may redeem our Preferred Units, in whole or in part, at a redemption price of
$25.00 per unit plus an amount equal to all accumulated and unpaid distributions to, but not including, the date of redemption,
whether or not declared. We may also redeem the Preferred Units upon the occurrence of certain rating events or a change of
control as defined in our partnership agreement. In the case of the latter instance, if we choose not to redeem the Preferred
Units, the preferred unitholders may have the ability to convert the Preferred Units to common units at the then applicable
conversion rate. Preferred unitholders have no voting rights except for certain exceptions set forth in our partnership agreement.
Issuance of Common Units
During the year ended December 31, 2016, we issued 595,050 common units representing limited partner interests at an
average price of $47.39 per unit for proceeds of $28.3 million, net of $0.5 million of issuance costs. We used these proceeds,
which includes a contribution of $0.6 million from our general partner to maintain its 2% general partner interest, for general
partnership purposes, including repayments of outstanding borrowings under the Revolving Credit Agreement.
For the year ended December 31, 2016, we issued 135,100 common units representing limited partner interests in connection
with vesting of awards issued under our long-term incentive plan.
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Accumulated Other Comprehensive Income (Loss)
The balance of and changes in the components included in “Accumulated other comprehensive income (loss)” were as follows:
Balance as of December 31, 2014
(28,839)
(39,073)
Balance as of January 1, 2014
Other comprehensive loss before
reclassification adjustments
Net loss on cash flow hedges reclassified into interest
expense, net
Other comprehensive (loss) income
Other comprehensive (loss) income before
reclassification adjustments
Net loss on cash flow hedges reclassified into interest
expense, net
Other comprehensive (loss) income
Balance as of December 31, 2015
Employee Transfer
Deferred income tax adjustments
Other comprehensive loss before
reclassification adjustments
Net gain on pension costs reclassified into operating
expense
Net gain on pension costs reclassified into general and
administrative expense
Net loss on cash flow hedges reclassified into interest
expense, net
Other comprehensive (loss) income
Foreign
Currency
Translation
Cash Flow
Hedges
Pension and
Other
Postretirement
Benefits
Total
(Thousands of Dollars)
$
(13,658) $
(49,736) $
— $
(63,394)
(15,181)
—
(15,181)
—
10,663
10,663
(31,987)
1,303
—
(31,987)
9,802
11,105
(60,826)
(27,968)
—
—
—
—
—
—
—
—
(15,181)
10,663
(4,518)
(67,912)
(30,684)
9,802
(20,882)
(88,794)
4,201
2,414
—
—
—
—
4,201
2,414
(8,243)
(2,621)
(7,852)
(18,716)
—
—
—
(8,243)
—
—
8,331
5,710
(1,200)
(1,200)
(413)
(413)
—
(2,850)
8,331
(5,383)
Balance as of December 31, 2016
$
(69,069) $
(22,258) $
(2,850) $
(94,177)
The following table details the calculation of net income applicable to the general partner:
Net income attributable to NuStar Energy L.P.
Less preferred limited partner interest
Less general partner incentive distribution
Net income after general partner incentive distribution and preferred
limited partner interest
General partner interest allocation
General partner interest allocation of net income
General partner incentive distribution
Net income applicable to general partner
Year Ended December 31,
2016
2015
2014
(Thousands of Dollars)
$
150,003
$
306,720
$
210,773
1,925
43,407
—
43,220
—
43,220
104,671
263,500
167,553
2%
2%
2%
2,091
43,407
45,498
$
5,270
43,220
48,490
$
3,352
43,220
46,572
$
90
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Common Unit and General Partner Distributions
We make quarterly distributions to common unitholders and the general partner of 100% of our available cash, generally
defined as cash receipts less cash disbursements (including Preferred Unit distributions) and cash reserves established by the
general partner, in its sole discretion. These quarterly distributions are declared and paid within 45 days subsequent to each
quarter-end. The common unitholders receive a minimum quarterly distribution of $0.60 per unit each quarter ($2.40
annualized), subject to limitation by the Preferred Unit distributions in arrears, if any. Our available cash is first distributed 98%
to the common unitholders and 2% to the general partner until the amount distributed to our common unitholders and general
partner is equal to the minimum quarterly distribution and arrearages in the payment of the minimum quarterly distribution for
any prior quarter. Cash in excess of the minimum quarterly distributions is distributed to our common unitholders and our
general partner based on the percentages shown below.
Our general partner is entitled to incentive distributions if the amount we distribute to holders of our common units with respect
to any quarter exceeds specified target levels shown below:
Quarterly Distribution Amount per Common Unit
Up to $0.60
Above $0.60 up to $0.66
Above $0.66
Percentage of Distribution
Common
Unitholders
98%
90%
75%
General
Partner
2%
10%
25%
The following table reflects the allocation of total cash distributions to the general and common limited partners applicable to
the period in which the distributions were earned:
General partner interest
General partner incentive distribution
Total general partner distribution
Common limited partners’ distribution
Total cash distributions
Cash distributions per unit applicable to common limited partners
Year Ended December 31,
2016
2015
2014
(Thousands of Dollars, Except Per Unit Data)
7,877
$
7,844
$
43,407
51,284
342,598
393,882
4.380
$
$
43,220
51,064
341,140
392,204
4.380
$
$
7,844
43,220
51,064
341,140
392,204
4.380
$
$
$
The following table summarizes information related to our quarterly cash distributions to our general and common limited
partners:
Quarter Ended
December 31, 2016 (a)
September 30, 2016
June 30, 2016
March 31, 2016
Cash
Distributions
Per Unit
Total Cash
Distributions
(Thousands of Dollars)
Record Date
Payment Date
$
$
$
$
1.095
1.095
1.095
1.095
$
$
$
$
98,971
February 8, 2017
February 13, 2017
98,809 November 8, 2016 November 14, 2016
98,051
98,051
August 9, 2016
August 12, 2016
May 9, 2016
May 13, 2016
(a) The distribution was announced on January 27, 2017.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
21. NET INCOME PER UNIT
The following table details the calculation of net income per unit:
Year Ended December 31,
2016
2015
2014
(Thousands of Dollars, Except Per Unit Data)
Net income attributable to NuStar Energy L.P.
$
150,003
$
306,720
$
210,773
Less: Distributions to general partner (including incentive
distribution rights)
Less: Distributions to common limited partners
Less: Distributions for preferred limited partners
Less: Distribution equivalent rights to restricted units
Distributions in excess of earnings
Net income attributable to common units:
Distributions to common limited partners
Allocation of distributions in excess of earnings
Total
51,284
342,598
1,925
51,064
341,140
—
51,064
341,140
—
2,697
(248,501) $
—
(85,484) $
—
(181,431)
342,598
(243,530)
99,068
$
$
341,140
(83,774)
257,366
$
$
341,140
(177,801)
163,339
$
$
$
Basic weighted-average common units outstanding
78,080,484
77,886,078
77,886,078
Diluted common units outstanding:
Basic weighted-average common units outstanding
Effect of dilutive potential common units
Diluted weighted-average common units outstanding
Basic and diluted net income per common unit
78,080,484
77,886,078
77,886,078
32,518
—
—
78,113,002
77,886,078
77,886,078
$
1.27
$
3.30
$
2.10
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
22. STATEMENTS OF CASH FLOWS
Changes in current assets and current liabilities were as follows:
Year Ended December 31,
2016
2015
2014
(Thousands of Dollars)
Decrease (increase) in current assets:
Accounts receivable
Receivable from related parties
Inventories
Other current assets
Increase (decrease) in current liabilities:
Accounts payable
Payable to related party
Accrued interest payable
Accrued liabilities
Taxes other than income tax
Income tax payable
$
(23,234) $
(317)
940
8,128
67,257
$
—
16,776
4,414
14,071
894
(256)
161
2,690
639
(32,152)
(872)
941
(7,834)
(1,522)
3,551
Changes in current assets and current liabilities
$
3,716
$
50,559
$
72,298
50,918
82,075
3,785
(153,671)
837
303
22,980
4,341
(1,448)
82,418
The above changes in current assets and current liabilities differ from changes between amounts reflected in the applicable
consolidated balance sheets due to:
•
•
•
•
•
current assets and current liabilities acquired and disposed during the period;
the change in the amount accrued for capital expenditures;
the effect of foreign currency translation;
reclassification of the Axeon Term Loan to other current assets from other long-term assets, net; and
non-cash related party transactions associated with the Employee Transfer (see Note 18 for further information).
Non-cash financing activities for the years ended December 31, 2016 and 2015 mainly consist of changes in the fair values of
our interest rate swap agreements.
Cash flows related to interest and income taxes were as follows:
Cash paid for interest, net of amount capitalized
Cash paid for income taxes, net of tax refunds received
$
$
142,663
11,847
$
$
133,388
9,971
$
$
129,377
6,699
Year Ended December 31,
2016
2015
2014
(Thousands of Dollars)
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
23. EMPLOYEE BENEFIT PLANS
Employee Transfer
On March 1, 2016, and in conjunction with the Employee Transfer, we assumed $22.5 million and $10.2 million in benefit
obligations associated with the pension plans and other postretirement benefit plans, respectively. Prior to the Employee
Transfer, we reimbursed all costs incurred by NuStar GP, LLC related to these employee benefit plans at cost. For
comparability purposes this footnote presents information related to these benefit plans on a combined basis for periods prior to
the Employee Transfer and after the Employee Transfer, including changes in the benefit obligation and fair value of plan
assets, components of net periodic benefit cost (income), and adjustments to other comprehensive income (loss). Consequently,
certain amounts presented below will differ from amounts reflected in our consolidated financial statements. See Note 18 for
additional discussion on the Employee Transfer.
Thrift Plans
The NuStar Thrift Plan (the Thrift Plan) is a qualified defined contribution plan that became effective June 26, 2006.
Participation in the Thrift Plan is voluntary and open to substantially all our domestic employees upon their date of hire. Thrift
Plan participants can contribute from 1% up to 30% of their total annual compensation to the Thrift Plan in the form of pre-tax
and/or after tax employee contributions. We make matching contributions in an amount equal to 100% of each participant’s
employee contributions up to a maximum of 6% of the participant’s total annual compensation. The matching contributions to
the Thrift Plan for the years ended December 31, 2016, 2015 and 2014 totaled $6.6 million, $6.3 million and $5.9 million,
respectively.
The NuStar Excess Thrift Plan (the Excess Thrift Plan) is a nonqualified deferred compensation plan that became effective
July 1, 2006. The Excess Thrift Plan provides benefits to those employees whose compensation and/or annual contributions
under the Thrift Plan are subject to the limitations applicable to qualified retirement plans under the Code.
We also maintain several other defined contribution plans for certain international employees located in Canada, the
Netherlands and the United Kingdom. For the years ended December 31, 2016, 2015 and 2014, our costs for these plans
totaled $2.4 million, $2.6 million and $2.7 million, respectively.
Pension and Other Postretirement Benefits
The NuStar Pension Plan (the Pension Plan) is a qualified non-contributory defined benefit pension plan that provides eligible
U.S. employees with retirement income as calculated under a cash balance formula. Under the cash balance formula, benefits
are determined based on age, service and interest credits, and employees become fully vested in their benefits upon attaining
three years of vesting service. Prior to January 1, 2014, eligible employees were covered under either a cash balance formula or
a final average pay formula (FAP). Effective January 1, 2014, the Pension Plan was amended to freeze the FAP benefits as of
December 31, 2013, and going forward, all eligible employees are covered under the cash balance formula discussed above.
We also maintain an excess pension plan (the Excess Pension Plan), which is a nonqualified deferred compensation plan that
provides benefits to a select group of management or other highly compensated employees. Neither the Excess Thrift Plan nor
the Excess Pension Plan is intended to constitute either a qualified plan under the provisions of Section 401 of the Code or a
funded plan subject to the Employee Retirement Income Security Act.
The Pension Plan, Excess Pension Plan and the supplemental executive retirement plan (the SERP), which has no participants
following final payouts in 2014, are collectively referred to as the Pension Plans in the tables and discussion below. Our other
postretirement benefit plans include a contributory medical benefits plan for U.S. employees that retired prior to April 1, 2014
and for employees that retire on or after April 1, 2014, a partial reimbursement for eligible third-party health care premiums.
We use December 31 as the measurement date for our pension and other postretirement plans.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The changes in the benefit obligation, the changes in fair value of plan assets, the funded status and the amounts recognized in
the consolidated balance sheets for our Pension Plans and other postretirement benefit plans as of and for the years ended
December 31, 2016 and 2015 were as follows:
Change in benefit obligation:
Benefit obligation, January 1
Service cost
Interest cost
Benefits paid
Participant contributions
Actuarial loss (gain)
Benefit obligation, December 31
Change in plan assets:
Plan assets at fair value, January 1
Actual return on plan assets
Employer contributions
Benefits paid
Participant contributions
Plan assets at fair value, December 31
Reconciliation of funded status:
Fair value of plan assets at December 31
Less: Benefit obligation at December 31
Funded status at December 31
Amounts recognized in the consolidated balance sheets (b):
Accrued liabilities
Other long-term liabilities
Net pension liability
Pension Plans (a)
Other Postretirement
Benefit Plans (a)
2016
2015
2016
2015
(Thousands of Dollars)
$
109,202
$
106,848
$
10,042
$
10,484
7,703
4,023
(2,554)
—
9,028
127,402
$
7,676
4,389
(4,338)
—
(5,373)
109,202
419
401
(422)
253
368
$
11,061
$
87,706
$
83,365
$
— $
6,891
15,601
(2,554)
—
645
8,034
(4,338)
—
—
169
(422)
253
107,644
$
87,706
$
— $
470
448
(507)
203
(1,056)
10,042
—
—
304
(507)
203
—
107,644
$
87,706
$
— $
—
127,402
(19,758) $
109,202
(21,496) $
11,061
(11,061) $
10,042
(10,042)
(162) $
(19,596)
(19,758) $
(71) $
(321) $
(21,425)
(21,496) $
(10,740)
(11,061) $
(304)
(9,738)
(10,042)
$
$
$
$
$
$
$
(a) Certain amounts shown will differ from amounts reflected in our consolidated financial statements due to the Employee Transfer on
March 1, 2016.
(b) For the Pension Plan, since assets exceed the present value of expected benefit payments for the next 12 months, all of the liability
is noncurrent. For the Excess Pension Plan and the other postretirement benefit plans, since there are no assets, the current liability
is the present value of expected benefit payments for the next 12 months; the remainder is noncurrent.
The accumulated benefit obligation is the present value of benefits earned to date, assuming no future salary increases. The
aggregate accumulated benefit obligation for our Pension Plans as of December 31, 2016 and 2015 was $125.0 million and
$108.2 million, respectively. As of December 31, 2016 and 2015, the aggregate accumulated benefit obligation for the Pension
Plans exceeded plan assets.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The components of net periodic benefit cost (income) related to our Pension Plans and other postretirement benefit plans were
as follows:
Pension Plans (a)
Other Postretirement
Benefit Plans (a)
Year Ended December 31,
Year Ended December 31,
2016
2015
2014
2016
2015
2014
(Thousands of Dollars)
$
7,703
$
7,676
$
8,049
$
Service cost
Interest cost
Expected return on plan assets
Amortization of prior service credit
Amortization of net actuarial loss
Other
4,023
(5,407)
(2,063)
1,091
—
4,389
(5,018)
(2,063)
1,845
—
Net periodic benefit cost (income) $
5,347
$
6,829
$
$
419
401
$
470
448
—
(1,145)
181
—
(1,145)
269
—
(144) $
$
—
42
$
4,225
(4,574)
(2,063)
179
(39)
5,777
374
373
—
(1,145)
114
—
(284)
(a) Certain amounts shown will differ from amounts reflected in our consolidated financial statements due to the Employee Transfer on
March 1, 2016.
We amortize the prior service credit shown in the table above on a straight-line basis of the credit over the average remaining
service period of employees expected to receive benefits under our Pension Plans and other postretirement benefit plans. We
amortize the net actuarial loss shown in the table above on a straight-line basis of the excess of the unrecognized loss over 10
percent of the greater of the projected benefit obligation or market-related value of plan assets (smoothed asset value) over the
average remaining service period of active employees expected to receive benefits under our Pension Plans and other
postretirement benefit plans.
Adjustments to other comprehensive (loss) income related to our Pension Plans and other postretirement benefit plans were as
follows:
Pension Plans (a)
Other Postretirement
Benefit Plans (a)
Year Ended December 31,
Year Ended December 31,
2016
2015
2014
2016
2015
2014
(Thousands of Dollars)
Net unrecognized (loss) gain arising
during the year:
Net actuarial (loss) gain
$
(7,544) $
1,000
$
(14,716) $
(368) $
1,056
$
(2,718)
Net (gain) loss reclassified into
income:
Amortization of prior service credit
Amortization of net actuarial loss
Net (gain) loss reclassified into
income
Income tax benefit (expense)
Total changes to other
comprehensive (loss) income
(2,063)
1,091
(2,063)
1,845
(2,063)
179
(1,145)
181
(1,145)
269
(1,145)
114
(972)
(218)
(1,884)
(964)
(876)
(1,031)
57
(362)
5,314
3
(382)
984
$
(8,459) $
420
$
(11,286) $
(1,329) $
(202) $
(2,765)
(a) Certain amounts shown will differ from amounts reflected in our consolidated financial statements due to the Employee Transfer on
March 1, 2016.
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The amounts recorded as a component of accumulated other comprehensive loss related to our Pension Plans and other
postretirement benefit plans were as follows:
Unrecognized actuarial loss (b)
Prior service credit (b)
Deferred tax asset (liability)
Accumulated other comprehensive (loss) income,
net of tax
Pension Plans (a)
December 31,
Other Postretirement
Benefit Plans (a)
December 31,
2016
2015
2016
2015
(28,427) $
18,663
(Thousands of Dollars)
(21,975) $
20,727
57
1,313
(3,755) $
10,609
3
(3,568)
11,754
(3,726)
(9,707) $
65
$
6,857
$
4,460
$
$
(a) Certain amounts shown will differ from amounts reflected in our consolidated financial statements due to the Employee Transfer on
March 1, 2016.
(b) Represents the balance of accumulated other comprehensive income (loss) that has not been recognized as a component of net
periodic benefit cost (income).
The following pre-tax amounts in accumulated other comprehensive loss as of December 31, 2016 are expected to be
recognized as components of net periodic benefit cost (income) in 2017:
Actuarial loss
Prior service credit
Pension Plans
Other
Postretirement
Benefit Plans
(Thousands of Dollars)
$
$
1,484
$
(2,059) $
191
(1,145)
Investment Policies and Strategies
The investment policies and strategies for the assets of our qualified Pension Plan incorporate a well-diversified approach that
is expected to earn long-term returns from capital appreciation and a growing stream of current income. This approach
recognizes that assets are exposed to risk, and the market value of the Pension Plan’s assets may fluctuate from year to year.
Risk tolerance is determined based on our financial ability to withstand risk within the investment program and the willingness
to accept return volatility. In line with the investment return objective and risk parameters, the Pension Plan’s mix of assets
includes a diversified portfolio of equity and fixed-income instruments. The aggregate asset allocation is reviewed on an annual
basis. As of December 31, 2016, the target allocations for plan assets are 65% equity securities and 35% fixed income
investments, with certain fluctuations permitted.
The overall expected long-term rate of return on plan assets for the Pension Plan is estimated using various models of asset
returns. Model assumptions are derived using historical data with the assumption that capital markets are informationally
efficient. Three models are used to derive the long-term expected returns for each asset class. Since each method has distinct
advantages and disadvantages and differing results, an equal weighted average of the methods’ results is used.
Fair Value of Plan Assets
We disclose the fair value for each major class of plan assets in the Pension Plan into three levels: Level 1, defined as
observable inputs such as quoted prices for identical assets or liabilities in active markets; Level 2, defined as inputs other than
quoted prices in active markets that are either directly or indirectly observable, such as quoted prices for similar assets or
liabilities in active markets or quoted prices for identical assets or liabilities in markets that are not active; and Level 3, defined
as unobservable inputs for which little or no market data exists.
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The major classes of plan assets measured at fair value for the Pension Plan, were as follows:
Cash equivalent securities
Equity securities:
U.S. large cap equity fund (a)
International stock index fund (b)
Fixed income securities:
Bond market index fund (c)
Total
Cash equivalent securities
Equity securities:
U.S. large cap equity fund (a)
International stock index fund (b)
Fixed income securities:
Bond market index fund (c)
Total
December 31, 2016
Level 1
Level 2
Level 3
Total
738
$
(Thousands of Dollars)
— $
— $
738
—
10,459
64,813
—
—
—
64,813
10,459
31,634
42,831
$
—
64,813
$
—
— $
31,634
107,644
December 31, 2015
Level 1
Level 2
Level 3
Total
(Thousands of Dollars)
739
$
— $
— $
739
$
$
$
—
8,522
26,359
52,086
—
—
—
—
—
$
35,620
$
52,086
$
— $
52,086
8,522
26,359
87,706
(a) This fund is a low-cost equity index fund not actively managed that tracks the S&P 500. Fair values were estimated using pricing
models, quoted prices of securities with similar characteristics or discounted cash flows.
(b) This fund tracks the performance of the Total International Composite Index.
(c) This fund tracks the performance of the Barclays Capital U.S. Aggregate Bond Index.
Contributions to the Pension Plans
For the year ended December 31, 2016, we contributed $15.6 million and $0.2 million to the Pension Plans and other
postretirement benefit plans, respectively. During 2017, we expect to contribute approximately $11.2 million and $0.3 million
to the Pension Plans and other postretirement benefit plans, respectively, which principally represents contributions either
required by regulations or laws, or with respect to unfunded plans, necessary to fund current benefits.
Estimated Future Benefit Payments
The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid for the years
ending December 31:
2017
2018
2019
2020
2021
Years 2022-2026
Pension Plans
Other
Postretirement
Benefit Plans
(Thousands of Dollars)
$
$
$
$
$
$
7,747
8,418
9,190
9,656
10,048
59,168
$
$
$
$
$
$
321
359
399
429
460
2,949
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Assumptions
The weighted-average assumptions used to determine the benefit obligations were as follows:
Discount rate
Rate of compensation increase
Pension Plans
December 31,
Other
Postretirement
Benefit Plans
December 31,
2016
2015
2016
2015
4.33%
3.51%
4.61%
3.51%
4.49%
n/a
4.75%
n/a
The weighted-average assumptions used to determine the net periodic benefit cost (income) were as follows:
Discount rate
Expected long-term rate of
return on plan assets
Rate of compensation increase
Pension Plans
Year Ended December 31,
Other Postretirement
Benefit Plans
Year Ended December 31,
2016
2015
2014
2016
2015
2014
4.61%
4.22%
5.04%
4.75%
4.34%
5.28%
6.25%
3.51%
6.50%
3.51%
6.75%
3.51%
n/a
n/a
n/a
n/a
n/a
n/a
The assumed health care cost trend rates were as follows:
Health care cost trend rate assumed for next year
Rate to which the cost trend rate was assumed to decrease to (the ultimate trend rate)
Year that the rate reached the ultimate trend rate
December 31,
2016
2015
6.84%
5.00%
2028
6.81%
5.00%
2026
Assumed health care cost trend rates have a significant effect on the amounts reported for health care plans. We sponsor a
contributory postretirement health care plan for employees that retired prior to April 1, 2014. The plan has an annual limitation
(a cap) on the increase of the employer’s share of the cost of covered benefits. The cap on the increase in employer’s cost is
2.5% per year. The assumed increase in total health care cost exceeds the 2.5% indexed cap, so increasing or decreasing the
health care cost trend rate by 1% does not materially change our obligation or expense for the postretirement health care plan.
24. UNIT-BASED COMPENSATION
Overview
On January 28, 2016, our unitholders approved the Fifth Amended and Restated 2000 Long-Term Incentive Plan (the Amended
2000 LTIP) which, among other items, provides that we may use newly issued common units from NuStar Energy to satisfy
unit awards and extends the term of the Amended 2000 LTIP to January 28, 2026. Prior to the Employee Transfer, NuStar GP,
LLC sponsored the Amended 2000 LTIP, and we reimbursed NuStar GP, LLC for awards under this plan. Upon the approval of
the Amended 2000 LTIP, along with the Employee Transfer, most of our currently outstanding awards are now classified as
equity-classified awards as we intend to settle these awards through the issuance of our common units.
Effective March 1, 2016, we assumed sponsorship of the Amended 2000 LTIP, which provides the Compensation Committee of
the Board of Directors of NuStar GP, LLC (the Compensation Committee) with the right to issue and award up to 3,250,000 of
our common units to employees and non-employee directors. Awards available under the Amended 2000 LTIP include restricted
units, performance units, unit options, unit awards and distribution equivalent rights (DERs). The Compensation Committee
may also include a tandem grant of a DER that will entitle the participant to receive cash equal to cash distributions made on
any award prior to its vesting. As of December 31, 2016, common units that remained available to be awarded under the
Amended 2000 LTIP totaled 990,018.
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
On March 1, 2016, we assumed all outstanding awards under the Amended 2000 LTIP. The transfer of the outstanding awards
qualifies as a plan modification. Therefore, we measured the fair value of the outstanding awards based on the common unit
price on the transfer date.
The following table summarizes information pertaining to our long-term incentive plan compensation expense:
Restricted Units:
Domestic employees
Non-employee directors (NEDs)
International employees
Performance Units
Total
Transferred Units
March 1, 2016
Units Outstanding
December 31, 2016
Compensation Expense
Year Ended
December 31, 2016
(Thousands of Dollars)
586,524
17,629
49,121
77,014
730,288
647,340
$
18,134
50,609
77,014
793,097
$
5,980
388
715
1,211
8,294
Prior to the Employee Transfer, we reimbursed NuStar GP, LLC for our long-term incentive plan compensation expense which
totaled $6.4 million and $10.9 million for the years ended December 31, 2015 and 2014, respectively.
Restricted Units
Our restricted unit awards are considered phantom units as they represent the right to receive our common units upon vesting.
We account for restricted units as either equity-classified awards or liability-classified awards depending on expected method of
settlement. Awards we settle with the issuance of common units upon vesting are equity-classified. Awards we settle in cash
upon vesting are liability-classified. We record compensation expense ratably over the vesting period based on the fair value of
the common units at the grant date (for domestic employees) or the fair value of the common units measured at each reporting
period (for NEDs and international employees). DERs paid with respect to outstanding equity-classified unvested restricted
units reduce equity, similar to cash distributions to unitholders, whereas DERs paid with respect to outstanding liability-
classified unvested restricted units are expensed. Cash payments made or to be made in connection with DERs were $2.7
million for the year ended December 31, 2016.
The total fair value of our equity-classified awards vested from the Employee Transfer date to December, 31, 2016 was $9.0
million. We issued 135,100 common units in connection with these award vestings, net of employee tax withholding
requirements, for the year ended December 31, 2016. Unrecognized compensation cost related to our equity-classified
employee awards totaled $24.6 million as of December 31, 2016, which we expect to recognize over a weighted-average period
of 3.9 years. A summary of our restricted unit activity is as follows:
Nonvested units as of January 1, 2016
Transferred
Granted
Vested
Forfeited
Nonvested units as of December 31, 2016
Domestic Employees
Number of
Restricted
Units
— $
586,524
246,070
(180,724)
(4,530)
647,340
$
Weighted-
Average
Grant-Date
Fair Value
Per Unit
Number of
Restricted
Units to
NEDs
Number of
Restricted
Units to
International
Employees
—
35.03
47.70
35.50
35.03
39.72
—
17,629
8,730
(8,225)
—
18,134
—
49,121
20,107
(14,812)
(3,807)
50,609
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Domestic Employees. The outstanding restricted units granted to domestic employees are equity-classified awards and generally
vest over five years beginning one year after the grant date. The fair value of these awards is measured at the transfer date (or
grant date for issuances subsequent to the Employee Transfer).
Non-Employee Directors. The outstanding restricted units granted to NEDs are equity-classified awards that vest over three
years. The fair value of these awards is equal to the market price of our common units at each reporting period.
International Employees. The outstanding restricted units granted to international employees are cash-settled and accounted for
as liability-classified awards. These awards vest over three to five years and the fair value is equal to the market price of our
common units at each reporting period. We accrued $0.4 million for these awards as of December 31, 2016, which is included
in “Accrued liabilities” on our consolidated balance sheet. We paid or expect to pay $0.7 million in cash to settle the 2016
restricted unit vestings.
Performance Units
Performance units are issued to certain of our key employees and represent rights to receive our common units upon achieving
an objective performance measure for the performance period. The objective performance measure is determined each year by
the NuStar GP, LLC Compensation Committee for the following year. Achievement of the performance measure determines the
rate at which the performance units convert into our common units, which can range from zero to 200%.
Performance units vest in three annual increments (tranches), based upon our achievement of the performance measure set by
the Compensation Committee during the one-year performance periods that end on December 31 of each year following the
date of grant. Therefore, the performance units are not considered granted until the Compensation Committee has set the
performance measure for each tranche of awards. Performance units are equity-classified awards measured at the grant date fair
value. In addition, since the performance units granted do not receive DERs, the grant date fair value of these awards is
adjusted for the per unit distributions expected to be paid to common unitholders during the vesting period. We record
compensation expense ratably for each vesting tranche over its requisite service period (one year) if it is probable that the
specified performance measure will be achieved. Additionally, changes in the actual or estimated outcomes that affect the
quantity of performance units expected to be converted are recognized as a cumulative adjustment.
NuStar GP, LLC transferred 77,014 performance units on the Employee Transfer date. However, of the units transferred only
35,373 are considered granted for accounting purposes as the performance measure for the remaining tranches have not yet
been set. For the period from the Employee Transfer date to December 31, 2016, no performance units were granted or
forfeited. The fair value of awards subject to vesting for the year ended December 31, 2016 was recognized based on an
expected conversion to common unit rate of 150% (or 53,063 performance units) at a weighted-average grant-date fair value of
$31.75.
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25. INCOME TAXES
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Components of income tax expense related to certain of our continuing operations conducted through separate taxable wholly
owned corporate subsidiaries were as follows:
Current:
U.S.
Foreign
Foreign withholding tax
Total current
Deferred:
U.S.
Foreign
Foreign withholding tax
Total deferred
Year Ended December 31,
2016
2015
2014
(Thousands of Dollars)
$
$
2,280
6,329
3,833
12,442
$
908
9,820
1,926
12,654
2,680
(1,122)
(2,027)
(469)
1,022
(1,464)
2,500
2,058
(182)
7,516
—
7,334
1,889
1,578
—
3,467
Total income tax expense
$
11,973
$
14,712
$
10,801
The difference between income tax expense recorded in our consolidated statements of income and income taxes computed by
applying the statutory federal income tax rate (35% for all years presented) to income before income tax expense is due to the
fact that the majority of our income is not subject to federal income tax due to our status as a limited partnership. We record a
tax provision related to the amount of undistributed earnings of our foreign subsidiaries expected to be repatriated.
The tax effects of significant temporary differences representing deferred income tax assets and liabilities were as follows:
Deferred income tax assets:
Net operating losses
Employee benefits
Environmental and legal reserves
Allowance for bad debt
Other
Total deferred income tax assets
Less: Valuation allowance
Net deferred income tax assets
Deferred income tax liabilities:
Property, plant and equipment
Foreign withholding tax
Total deferred income tax liabilities
Net deferred income tax liability
Reported on the consolidated balance sheets as:
Deferred income tax asset
Deferred income tax liability
Net deferred income tax liability
102
December 31,
2016
2015
(Thousands of Dollars)
$
31,539
697
148
2,697
1,697
36,778
(12,759)
24,019
(43,788)
(384)
(44,172)
33,043
—
894
2,698
1,758
38,393
(13,151)
25,242
(44,880)
(2,314)
(47,194)
(20,153) $
(21,952)
$
2,051
(22,204)
(20,153) $
2,858
(24,810)
(21,952)
$
$
$
$
Table of Contents
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
As of December 31, 2016, our U.S. and foreign corporate operations have net operating loss carryforwards for tax purposes
totaling approximately $80.0 million and $11.9 million, respectively, which are subject to various limitations on use and expire
in years 2025 through 2036 for U.S. losses and in years 2017 through 2024 for foreign losses.
As of December 31, 2016 and 2015, we recorded a valuation allowance of $12.8 million and $13.2 million, respectively, related
to our deferred tax assets. We estimate the amount of valuation allowance based upon our expectations of taxable income in the
various jurisdictions in which we operate and the period over which we can utilize those future deductions. The valuation
allowance reflects uncertainties related to our ability to utilize certain net operating loss carryforwards before they expire. In
2016, there was no change in the valuation allowance for the U.S. net operating loss and a $0.4 million decrease in the foreign
net operating loss valuation allowance due to changes in our estimates of the amount of those loss carryforwards that will be
realized, based upon future taxable income.
The realization of net deferred income tax assets recorded as of December 31, 2016 is dependent upon our ability to generate
future taxable income in the United States. We believe it is more likely than not that the net deferred income tax assets as of
December 31, 2016 will be realized, based on expected future taxable income.
St. Eustatius Tax Agreement
On February 22, 2006, we entered into a Tax and Maritime Agreement with the governments of St. Eustatius and the
Netherlands Antilles (the 2005 Tax Agreement). The 2005 Tax Agreement was effective beginning January 1, 2005 and expired
on December 31, 2014. The 2005 Tax Agreement provided for an annual minimum profit tax of approximately $0.6 million,
beginning as of January 1, 2005.
Effective January 1, 2011, the Netherlands Antilles ceased to exist, and St. Eustatius became part of the Netherlands. The
Netherlands Tax Ministry (the Ministry) contends that as of January 2011, we are subject to real estate tax rather than profit tax
as expressed in our 2005 Tax Agreement. In 2013, the Ministry issued a property tax assessment for years 2011 through 2012.
We objected to and appealed the assessment. The Ministry later issued property tax assessments for the years 2013 and 2014,
to which we have or will file similar objections. In 2013, we filed a lawsuit in the Netherlands civil court seeking to enforce the
terms of our existing 2005 Tax Agreement. In 2016, we settled this dispute by agreement and are current with our property tax
obligations in St. Eustatius.
26. SEGMENT INFORMATION
Our reportable business segments consist of pipeline, storage and fuels marketing. Our segments represent strategic business
units that offer different services and products. We evaluate the performance of each segment based on its respective operating
income, before general and administrative expenses and certain non-segmental depreciation and amortization expense. General
and administrative expenses are not allocated to the operating segments since those expenses relate primarily to the overall
management at the entity level. Our principal operations include the transportation of petroleum products and anhydrous
ammonia, the terminalling and storage of petroleum products and the marketing of petroleum products. Intersegment revenues
result from storage agreements with wholly owned subsidiaries of NuStar Energy at rates consistent with the rates charged to
third parties for storage. Related party revenues in 2014 mainly resulted from storage agreements with our joint ventures.
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Results of operations for the reportable segments were as follows:
Revenues:
Pipeline
Storage:
Third parties
Intersegment
Related party
Total storage
Fuels marketing
Consolidation and intersegment eliminations
Total revenues
Depreciation and amortization expense:
Pipeline
Storage
Fuels marketing
Total segment depreciation and amortization expense
Other depreciation and amortization expense
Total depreciation and amortization expense
Operating income:
Pipeline
Storage
Fuels marketing
Consolidation and intersegment eliminations
Total segment operating income
General and administrative expenses
Other depreciation and amortization expense
Total operating income
Revenues by geographic area are shown in the table below.
United States
Netherlands
Other
Consolidated revenues
Year Ended December 31,
2016
2015
2014
(Thousands of Dollars)
$
485,650
$
508,522
$
477,030
$
$
$
$
589,098
20,944
—
599,302
25,606
—
610,042
681,934
(20,944)
1,756,682
$
624,908
976,216
(25,606)
2,084,040
$
537,142
26,435
929
564,506
2,060,017
(26,435)
3,075,118
89,554
$
84,951
$
118,663
—
208,217
8,519
116,768
—
201,719
8,491
216,736
$
210,210
$
248,238
$
270,349
$
214,801
3,406
—
466,445
98,817
8,519
217,818
13,507
42
501,716
102,521
8,491
77,691
103,848
16
181,555
10,153
191,708
245,233
183,104
24,805
(32)
453,110
96,056
10,153
$
359,109
$
390,704
$
346,901
Year Ended December 31,
2016
2015
2014
(Thousands of Dollars)
$
$
1,352,936
$
1,599,088
$
2,276,609
313,395
90,351
386,282
98,670
705,207
93,302
1,756,682
$
2,084,040
$
3,075,118
For the years ended December 31, 2016, 2015 and 2014, Valero Energy Corporation accounted for approximately 18%, or
$310.0 million, 16%, or $331.7 million, and 9%, or $282.9 million, of our consolidated revenues, respectively. These revenues
were included in all of our reportable business segments. No other single customer accounted for 10% or more of our
consolidated revenues.
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Total amounts of property, plant and equipment, net by geographic area were as follows:
United States
Netherlands
Other
Consolidated long-lived assets
Total assets by reportable segment were as follows:
Pipeline
Storage
Fuels marketing
Total segment assets
Other partnership assets
Total consolidated assets
December 31,
2016
2015
(Thousands of Dollars)
$
$
3,086,337
$
3,049,334
469,061
166,885
449,406
184,831
3,722,283
$
3,683,571
December 31,
2016
2015
(Thousands of Dollars)
$
2,024,633
$
2,014,098
2,522,586
168,347
4,715,566
314,979
2,476,389
156,866
4,647,353
478,172
$
5,030,545
$
5,125,525
Capital expenditures, including acquisitions and investments in other noncurrent assets, by reportable segment were as follows:
Pipeline
Storage
Other partnership assets
Total capital expenditures
Year Ended December 31,
2016
2015
2014
(Thousands of Dollars)
88,373
$
175,657
$
206,641
5,001
285,258
9,957
244,713
108,457
3,795
300,015
$
470,872
$
356,965
$
$
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
27. CONDENSED CONSOLIDATING FINANCIAL STATEMENTS
NuStar Energy has no operations, and its assets consist mainly of its 100% indirectly owned subsidiaries, NuStar Logistics and
NuPOP. The senior and subordinated notes issued by NuStar Logistics are fully and unconditionally guaranteed by NuStar
Energy and NuPOP. As a result, the following condensed consolidating financial statements are presented as an alternative to
providing separate financial statements for NuStar Logistics and NuPOP.
Assets
Cash and cash equivalents
Receivables, net
Inventories
Other current assets
Intercompany receivable
Total current assets
Property, plant and equipment, net
Intangible assets, net
Goodwill
Investment in wholly owned
subsidiaries
Deferred income tax asset
Other long-term assets, net
Total assets
Liabilities and Partners’ Equity
Payables
Short-term debt
Accrued interest payable
Accrued liabilities
Taxes other than income tax
Income tax payable
Intercompany payable
Total current liabilities
Long-term debt
Deferred income tax liability
Other long-term liabilities
Total partners’ equity
Total liabilities and
partners’ equity
Condensed Consolidating Balance Sheets
December 31, 2016
(Thousands of Dollars)
NuStar
Energy
NuStar
Logistics
NuPOP
Non-Guarantor
Subsidiaries
Eliminations
Consolidated
$
$
$
5
870
3,040
—
2,216
—
61
120,350
— 1,308,415
1,434,026
931
— 1,935,172
71,033
—
149,453
—
— $
—
2,005
1,829
—
3,834
589,139
—
170,652
35,067
167,570
33,724
10,446
57,785
304,592
1,197,972
56,050
376,532
$
— $
—
—
—
(1,366,200)
(1,366,200)
35,942
170,610
37,945
132,686
—
377,183
— 3,722,283
127,083
—
696,637
—
1,964,736
—
1,255
$ 1,966,922
34,778
—
63,586
$ 3,688,048
1,221,717
—
28,587
$ 2,013,929
874,649
2,051
11,880
$ 2,823,726
(4,095,880)
—
—
—
2,051
105,308
$(5,462,080) $ 5,030,545
$
$
2,436
—
—
1,070
125
—
257,497
261,128
127,578
— 2,956,338
1,862
—
34,358
—
567,912
1,705,794
24,272
54,000
34,008
7,118
6,854
1,326
$
7,124
—
—
10,766
3,253
5
— 1,108,703
1,129,851
—
13
9,436
874,629
$
84,854
—
22
41,531
5,453
5,179
$
— $
—
—
—
—
—
— (1,366,200)
(1,366,200)
118,686
54,000
34,030
60,485
15,685
6,510
—
289,396
— 3,014,364
22,204
—
92,964
—
(4,095,880)
1,611,617
137,039
58,026
20,329
49,170
2,559,162
$ 1,966,922
$ 3,688,048
$ 2,013,929
$ 2,823,726
$(5,462,080) $ 5,030,545
106
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Condensed Consolidating Balance Sheets
December 31, 2015
(Thousands of Dollars)
NuStar
Energy
NuStar
Logistics
NuPOP
Non-Guarantor
Subsidiaries
Eliminations
Consolidated
Assets
Cash and cash equivalents
Receivables, net
Inventories
Other current assets
Intercompany receivable
Total current assets
Property, plant and equipment, net
Intangible assets, net
Goodwill
Investment in wholly owned
subsidiaries
Deferred income tax asset
Other long-term assets, net
Total assets
Liabilities and Partners’ Equity
Payables
Short-term debt
Accrued interest payable
Accrued liabilities
Taxes other than income tax
Income tax payable
Intercompany payable
Total current liabilities
Long-term debt
Long-term payable to related party
Deferred income tax liability
Other long-term liabilities
Total partners’ equity
Total liabilities and
partners’ equity
$
$
885
4
—
419
—
1,776
11,026
140
— 1,610,370
1,623,595
— 1,915,370
48,961
—
149,453
—
1,025
$
— $
—
3,648
497
—
4,145
570,415
—
170,652
117,973
144,645
33,325
19,513
$
— $
—
—
—
— (1,610,370)
(1,610,370)
118,862
145,064
38,749
31,176
—
333,851
— 3,683,571
112,011
—
696,637
—
315,456
1,197,786
63,050
376,532
2,205,904
—
933
$ 2,207,862
48,547
—
255,957
$ 4,041,883
1,031,162
—
26,329
$ 1,802,703
915,115
4,037
13,378
$ 2,885,354
(4,200,728)
(1,179)
—
—
2,858
296,597
$(5,812,277) $ 5,125,525
$
$
12
—
—
723
126
—
508,363
509,224
52,650
84,000
34,271
32,816
6,452
1,362
—
211,551
— 3,002,743
26,638
—
1,143
—
37,209
—
762,599
1,698,638
$
11,193
—
—
5,753
3,325
9
858,018
878,298
—
—
36
9,294
915,075
$
76,091
—
15
15,902
2,907
4,606
243,989
343,510
52,869
5,442
24,810
24,463
2,434,260
$
— $
—
—
—
—
—
(1,610,370)
(1,610,370)
139,946
84,000
34,286
55,194
12,810
5,977
—
332,213
— 3,055,612
32,080
—
(1,179)
24,810
70,966
—
(4,200,728)
1,609,844
$ 2,207,862
$ 4,041,883
$ 1,802,703
$ 2,885,354
$(5,812,277) $ 5,125,525
107
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Condensed Consolidating Statements of Income (Loss)
For the Year Ended December 31, 2016
(Thousands of Dollars)
NuStar
Energy
NuStar
Logistics
NuPOP
Non-Guarantor
Subsidiaries
$
— $
511,650
$
224,966
$ 1,021,804
$
Revenues
Costs and expenses
Operating (loss) income
Equity in earnings (loss)
of subsidiaries
Interest (expense) income, net
Other income (expense), net
Income (loss) before income tax
expense (benefit)
Income tax expense (benefit)
1,806
(1,806)
302,099
209,551
150,384
74,582
(13,769)
(139,827)
(58,264)
82,202
(744)
(26)
151,794
—
18
150,006
3
Net income (loss)
$
150,003
$
Eliminations
Consolidated
(1,738) $ 1,756,682
(1,738)
1,397,573
—
359,109
(376,263)
—
—
—
(138,350)
(58,783)
945,022
76,782
156,036
2,221
(511)
(2,309)
1,607
(3,916) $
156,014
(23)
156,037
234,528
10,386
(376,263)
—
161,976
11,973
$
224,142
$ (376,263) $
150,003
Revenues
Costs and expenses
Operating (loss) income
Equity in earnings (loss)
of subsidiaries
Interest (expense) income, net
Other income, net
Income from continuing
operations before income
tax (benefit) expense
Income tax (benefit) expense
Income from continuing
operations
Income from discontinued
operations, net of tax
Net income
Condensed Consolidating Statements of Income
For the Year Ended December 31, 2015
(Thousands of Dollars)
NuStar
Energy
NuStar
Logistics
NuPOP
Non-Guarantor
Subsidiaries
$
— $
547,959
$
215,469
$ 1,322,675
$
1,717
(1,717)
293,708
254,251
308,437
—
—
(7,257)
(137,847)
1,179
140,081
75,388
120,768
1,611
5
1,259,935
62,740
197,760
4,368
60,638
Eliminations
Consolidated
(2,063) $ 2,084,040
(2,105)
1,693,336
42
390,704
(619,708)
—
—
—
(131,868)
61,822
306,720
—
110,326
(392)
197,772
23
325,506
15,081
(619,666)
—
320,658
14,712
306,720
110,718
197,749
310,425
(619,666)
305,946
—
—
—
774
—
774
$
306,720
$
110,718
$
197,749
$
311,199
$ (619,666) $
306,720
108
Table of Contents
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Revenues
Costs and expenses
Operating (loss) income
Equity in earnings (loss)
of subsidiaries
Equity in (loss) earnings of
joint ventures
Interest (expense) income, net
Other income (expense), net
Income from continuing
operations before income
tax expense
Income tax expense
Income from continuing
operations
Loss from discontinued
operations, net of tax
Net income
Less net loss attributable to
noncontrolling interest
Net income attributable to
NuStar Energy L.P.
Condensed Consolidating Statements of Income
For the Year Ended December 31, 2014
(Thousands of Dollars)
NuStar
Energy
NuStar
Logistics
NuPOP
Non-Guarantor
Subsidiaries
$
— $
510,833
$
229,211
$ 2,344,750
$
1,753
(1,753)
287,614
223,219
149,955
79,256
2,298,540
46,210
Eliminations
Consolidated
(9,676) $ 3,075,118
(9,645)
2,728,217
(31)
346,901
212,527
(12,798)
62,946
142,238
(404,913)
—
—
—
—
(8,278)
(132,274)
511
—
89
(37)
13,074
959
4,025
—
—
—
4,796
(131,226)
4,499
210,774
70,380
142,254
1
5
23
206,506
10,772
(404,944)
—
224,970
10,801
210,773
70,375
142,231
195,734
(404,944)
214,169
—
210,773
(169)
70,206
—
142,231
(3,622)
192,112
—
(404,944)
(3,791)
210,378
—
—
—
(395)
—
(395)
$
210,773
$
70,206
$
142,231
$
192,507
$ (404,944) $
210,773
109
150,003
(8,243)
(2,850)
5,710
(5,383)
144,620
306,720
(31,987)
11,105
(20,882)
285,838
Table of Contents
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Condensed Consolidating Statements of Comprehensive Income
For the Year Ended December 31, 2016
(Thousands of Dollars)
Net income (loss)
$
150,003
$
(3,916) $
156,037
$
224,142
NuStar
Energy
NuStar
Logistics
NuPOP
Non-Guarantor
Subsidiaries
Eliminations
$ (376,263) $
Consolidated
Other comprehensive income (loss):
Foreign currency translation
adjustment
Net loss on pension and other
postretirement benefit
adjustments, net of tax benefit
Net gain on cash flow hedges
Total other comprehensive
income (loss)
—
—
—
—
—
—
5,710
5,710
—
—
—
—
Comprehensive income
$
150,003
$
1,794
$
156,037
$
(8,243)
(2,850)
—
(11,093)
213,049
—
—
—
—
$ (376,263) $
Condensed Consolidating Statements of Comprehensive Income
For the Year Ended December 31, 2015
(Thousands of Dollars)
Net income
$
306,720
$
110,718
$
197,749
$
311,199
NuStar
Energy
NuStar
Logistics
NuPOP
Non-Guarantor
Subsidiaries
Eliminations
$ (619,666) $
Consolidated
Other comprehensive income (loss):
Foreign currency translation
adjustment
Net gain on cash flow hedges
Total other comprehensive
income (loss)
—
—
—
—
11,105
11,105
—
—
—
Comprehensive income
$
306,720
$
121,823
$
197,749
$
(31,987)
—
(31,987)
279,212
—
—
—
$ (619,666) $
110
Table of Contents
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Condensed Consolidating Statements of Comprehensive Income
For the Year Ended December 31, 2014
(Thousands of Dollars)
Net income
$
210,773
$
70,206
$
142,231
$
192,112
NuStar
Energy
NuStar
Logistics
NuPOP
Non-Guarantor
Subsidiaries
Eliminations
$ (404,944) $
Consolidated
210,378
Other comprehensive income (loss):
Foreign currency translation
adjustment
Net gain on cash flow hedges
Total other comprehensive
income (loss)
—
—
—
3,723
10,663
14,386
—
—
—
(19,337)
—
(19,337)
—
—
—
(15,614)
10,663
(4,951)
Comprehensive income
210,773
84,592
142,231
172,775
(404,944)
205,427
Less comprehensive loss
attributable to noncontrolling
interest
Comprehensive income
—
—
—
(828)
—
(828)
173,603
$ (404,944) $
206,255
attributable to NuStar Energy L.P.
$
210,773
$
84,592
$
142,231
$
111
Table of Contents
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Condensed Consolidating Statements of Cash Flows
For the Year Ended December 31, 2016
(Thousands of Dollars)
Net cash provided by operating
activities
Cash flows from investing activities:
Capital expenditures
Change in accounts payable
related to capital expenditures
Acquisitions
Investment in subsidiaries
Net cash used in investing activities
Cash flows from financing activities:
Debt borrowings
Debt repayments
Issuance of units, net of
issuance costs
General partner contribution
Distributions to common unitholders
and general partner
Contributions from
(distributions to) affiliates
Net intercompany activity
Other, net
Net cash (used in) provided by
financing activities
Effect of foreign exchange rate
changes on cash
Net (decrease) increase in cash and
cash equivalents
Cash and cash equivalents as of the
beginning of the period
Cash and cash equivalents as of the
end of the period
NuStar
Energy
NuStar
Logistics
NuPOP
Non-Guarantor
Subsidiaries
Eliminations
Consolidated
$ 391,773
$
167,900
$
211,816
$
359,283
$ (694,011) $
436,761
(64,334)
(52,637)
(87,387)
—
—
—
—
—
(10,076)
(95,657)
—
(170,067)
(285)
—
(212,900)
(265,822)
—
—
—
212,900
212,900
(204,358)
(11,063)
(95,657)
—
(311,078)
— 1,406,729
— (1,456,152)
—
—
246,110
680
(702)
—
—
(88,089)
41,200
(36,300)
—
—
— 1,365,529
— (1,419,852)
246,110
680
—
—
—
—
—
—
(392,962)
(196,481)
(196,481)
(196,501)
589,463
(392,962)
—
(241,131)
(4,485)
—
255,326
(2,354)
—
250,487
—
108,352
(264,682)
(8,890)
(108,352)
—
—
—
—
(15,729)
(391,788)
2,168
54,006
(356,821)
481,111
(211,324)
—
(15)
885
$
870
$
—
1
4
5
—
—
—
2,721
(82,906)
117,973
—
—
—
2,721
(82,920)
118,862
$
— $
35,067
$
— $
35,942
112
Table of Contents
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Condensed Consolidating Statements of Cash Flows
For the Year Ended December 31, 2015
(Thousands of Dollars)
NuStar
Energy
NuStar
Logistics
NuPOP
Non-Guarantor
Subsidiaries
Eliminations
Consolidated
$ 389,967
$
237,780
$
119,928
$
365,588
$ (588,326) $
524,937
(201,388)
(39,533)
(83,887)
—
—
—
—
—
—
—
(4,950)
—
—
10,320
—
(196,018)
33
—
—
22
—
(39,478)
— 1,589,131
— (1,275,910)
—
—
—
—
—
—
—
—
—
(324,808)
(3,156)
(142,500)
(3,564)
17,132
4,867
(452,029)
— 1,683,631
— (1,316,910)
588,326
—
—
588,326
(392,204)
—
(3,746)
(29,229)
—
—
—
(12,729)
30,950
87,912
1,761
(142,500)
(3,564)
6,790
4,867
(216,533)
94,500
(41,000)
(196,122)
37,427
(141)
(105,336)
(12,729)
30,990
86,983
—
—
—
$
— $
117,973
$
— $
118,862
Net cash provided by operating
activities
Cash flows from investing activities:
Capital expenditures
Change in accounts payable
related to capital expenditures
Acquisitions
Investment in other long-term assets
Proceeds from sale or disposition
of assets
Proceeds from insurance recoveries
Net cash used in investing activities
Cash flows from financing activities:
Debt borrowings
Debt repayments
Distributions to common unitholders
and general partner
Net intercompany activity
Other, net
(392,204)
2,199
—
Net cash used in financing activities
(390,005)
(196,102)
(155,278)
(3,605)
(41,764)
(196,102)
115,652
—
(80,450)
Effect of foreign exchange rate
changes on cash
Net (decrease) increase in cash and
cash equivalents
Cash and cash equivalents as of the
beginning of the period
Cash and cash equivalents as of the
end of the period
—
(38)
923
$
885
$
—
(2)
6
4
113
Table of Contents
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Condensed Consolidating Statements of Cash Flows
For the Year Ended December 31, 2014
(Thousands of Dollars)
Net cash provided by operating
activities
Cash flows from investing activities:
Capital expenditures
Change in accounts payable
related to capital expenditures
Proceeds from sale or disposition
of assets
Increase in note receivable from
Axeon
Investment in subsidiaries
Other, net
Net cash used in investing activities
Cash flows from financing activities:
Debt borrowings
Debt repayments
Distributions to common unitholders
and general partner
Contributions from
(distributions to) affiliates
Net intercompany activity
Other, net
Net cash (used in) provided by
financing activities
Effect of foreign exchange rate
changes on cash
Net increase (decrease) in cash and
cash equivalents
Cash and cash equivalents as of the
beginning of the period
Cash and cash equivalents as of the
end of the period
NuStar
Energy
NuStar
Logistics
NuPOP
Non-Guarantor
Subsidiaries
Eliminations
Consolidated
$ 390,543
$
221,422
$
111,931
$
333,936
$ (539,309) $
518,523
—
—
—
—
(23)
23
—
(273,785)
(14,625)
(68,555)
8,741
651
(13,328)
—
(45)
(277,766)
789
(4,627)
22
—
13,340
—
(474)
25,339
—
—
(831)
(48,674)
—
—
—
—
(13,317)
—
(13,317)
(356,965)
4,903
26,012
(13,328)
—
(853)
(340,231)
— 1,318,619
— (1,121,670)
—
—
—
—
— 1,318,619
— (1,121,670)
(392,204)
(245,127)
(147,077)
(147,105)
539,309
(392,204)
—
1,680
—
—
83,387
(1,166)
—
35,620
—
(13,340)
(120,687)
8,259
13,340
—
(23)
—
—
7,070
(390,524)
34,043
(111,457)
(272,873)
552,626
(188,185)
—
19
—
(22,301)
904
22,307
—
—
—
(2,938)
9,451
77,532
—
—
—
(2,938)
(12,831)
100,743
$
923
$
6
$
— $
86,983
$
— $
87,912
114
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
28. QUARTERLY FINANCIAL DATA (UNAUDITED)
The following table summarizes quarterly financial data for the years ended December 31, 2016 and 2015:
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
Total
(Thousands of Dollars, Except Per Unit Data)
2016:
Revenues
Operating income
Net income (loss)
$
$
$
405,703
94,565
57,401
Basic and diluted net income (loss) per common unit $
0.57
Cash distributions per unit applicable to common
limited partners
2015:
Revenues
Operating income
Income from continuing operations
Income from discontinued
operations, net of tax
Net income
$
$
$
$
1.095
554,944
99,281
127,125
$
$
$
$
$
$
$
$
437,804
91,217
52,517
0.52
1.095
570,611
92,405
54,325
$
$
$
$
$
$
$
$
441,418
87,954
51,141
0.49
1.095
493,566
100,994
65,016
$
$
$
$
$
$
$
$
471,757
$ 1,756,682
85,373
$
(11,056) $
359,109
150,003
(0.31) $
1.27
1.095
$
4.380
464,919
$ 2,084,040
98,024
59,480
$
$
390,704
305,946
774
—
—
—
774
$
127,899
$
54,325
$
65,016
$
59,480
$
306,720
Basic and diluted net income per common unit:
Continuing operations
Discontinued operations
Total
Cash distributions per unit applicable to common
limited partners
$
$
$
1.46
0.01
1.47
1.095
$
$
$
0.54
—
0.54
1.095
$
$
$
0.68
—
0.68
1.095
$
$
$
0.61
—
0.61
1.095
$
$
$
3.29
0.01
3.30
4.380
The quarterly financial data in the table above includes the impact of a $58.7 million non-cash impairment charge on the Axeon
Term Loan in the fourth quarter of 2016 and a $56.3 million non-cash gain associated with the Linden Acquisition in the first
quarter of 2015.
115
Table of Contents
ITEM 9.
None.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
ITEM 9A.
CONTROLS AND PROCEDURES
DISCLOSURE CONTROLS AND PROCEDURES
Our management has evaluated, with the participation of the principal executive officer and principal financial officer of
NuStar GP, LLC, the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities
Exchange Act of 1934 (the Exchange Act)) as of the end of the period covered by this report, and has concluded that our
disclosure controls and procedures were effective as of December 31, 2016.
INTERNAL CONTROL OVER FINANCIAL REPORTING
(a)
Management’s Report on Internal Control over Financial Reporting.
Management’s report on NuStar Energy L.P.’s internal control over financial reporting required by Item 9A. appears in Item 8.
of this Form 10-K, and is incorporated herein by reference.
(b)
Attestation Report of the Registered Public Accounting Firm.
The report of KPMG LLP on NuStar Energy L.P.’s internal control over financial reporting appears in Item 8. of this Form 10-
K, and is incorporated herein by reference.
(c)
Changes in Internal Control over Financial Reporting.
There has been no change in our internal control over financial reporting that occurred during our last fiscal quarter that has
materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
ITEM 9B.
OTHER INFORMATION
None.
116
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PART III
ITEM 10.
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
DIRECTORS AND EXECUTIVE OFFICERS OF NUSTAR GP, LLC
We do not have directors or officers. The directors and officers of NuStar GP, LLC, the general partner of our general partner,
Riverwalk Logistics, L.P., perform all of our management functions. NuStar GP Holdings, LLC (NuStar GP Holdings), the sole
member of NuStar GP, LLC, selects the directors of NuStar GP, LLC (the Board). Officers of NuStar GP, LLC are appointed by
its directors.
Set forth below is certain information concerning the directors and executive officers of NuStar GP, LLC, effective as of
February 20, 2017.
Name
William E. Greehey
Bradley C. Barron
J. Dan Bates
Dan J. Hill
Robert J. Munch
W. Grady Rosier
Mary Rose Brown
Thomas R. Shoaf
Jorge A. del Alamo
Amy L. Perry
Karen M. Thompson
Age
80
51
72
76
65
68
60
58
47
48
49
Position Held with NuStar GP, LLC
Chairman of the Board
President, Chief Executive Officer and Director
Director
Director
Director
Director
Executive Vice President and Chief Administrative Officer
Executive Vice President and Chief Financial Officer
Senior Vice President and Controller
Senior Vice President, General Counsel-Corporate & Commercial
Law and Corporate Secretary
Senior Vice President and General Counsel-Litigation, Regulatory &
Environmental
As a limited partnership, we are not required by the NYSE rules to have a nominating committee. However, in 2013, the Board
created a Nominating/Governance & Conflicts Committee to identify candidates for membership on the Board. The members
of the Nominating/Governance & Conflicts Committee are Mr. Rosier (Chairman), Mr. Bates, Mr. Hill and Mr. Munch. In
accordance with our Corporate Governance Guidelines, individuals are considered for membership on the Board based on their
character, judgment, integrity, diversity, age, skills (including financial literacy), independence and experience in the context of
the overall needs of the Board. Our directors are also selected based on their knowledge about our industry and their respective
experience leading or advising large companies. We require that our directors have the ability to work collegially, exercise good
judgment and think critically. The Nominating/Governance & Conflicts Committee strives to find the best possible candidates
to represent the interests of NuStar Energy L.P. and its unitholders. As part of its annual self-assessment process, the Board and
each of its committees evaluates the mix of independent and non-independent directors, as well as the performance of the
directors and the committees, and the Board annually elects a presiding director.
The Board is led by its Chairman, Mr. Greehey. The Board has determined that separating the roles of Chairman and CEO is in
the best interest of unitholders at this time. In addition, the Board has appointed Mr. Hill as its presiding director to serve as a
point of contact for unitholders wishing to communicate with the Board and to lead executive sessions of the non-management
directors.
Mr. Greehey became Chairman of the Board in January 2002. He also has been the Chairman of the board of directors of
NuStar GP Holdings since March 2006. Mr. Greehey served as Chairman of the board of directors of Valero Energy
Corporation (Valero Energy) from 1979 through January 2007. Mr. Greehey was CEO of Valero Energy from 1979 through
December 2005, and President of Valero Energy from 1998 until January 2003.
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Mr. Barron became President, Chief Executive Officer and a director of NuStar GP, LLC and NuStar GP Holdings in January
2014. He served as Executive Vice President and General Counsel of NuStar GP, LLC and NuStar GP Holdings from February
2012 until his promotion in January 2014. From April 2007 to February 2012, he served as Senior Vice President and General
Counsel of NuStar GP, LLC and NuStar GP Holdings. Mr. Barron also served as Secretary of NuStar GP, LLC and NuStar GP
Holdings from April 2007 to February 2009. He served as Vice President, General Counsel and Secretary of NuStar GP, LLC
from January 2006 until April 2007 and as Vice President, General Counsel and Secretary of NuStar GP Holdings from March
2006 until his promotion in April 2007. He has been with NuStar GP, LLC since July 2003 and, prior to that, was with Valero
Energy from January 2001 to July 2003.
Mr. Bates became a director of NuStar GP, LLC in April 2006. He served as President and CEO of the Southwest Research
Institute from 1997 until October 2014 and continues to serve as a director and as President Emeritus of the Southwest
Research Institute. Mr. Bates also serves as a director of Signature Science L.L.C., Broadway Bank and Broadway Bankshares,
Inc. He served as Chairman or Vice Chairman of the board of directors of the Federal Reserve Bank of Dallas’ San Antonio
Branch from January 2005 through December 2009.
Mr. Hill became a director of NuStar GP, LLC in July 2004. From February 2001 through May 2004, he served as a consultant
to El Paso Corporation. Prior to that, he served as President and CEO of Coastal Refining and Marketing Company. In 1978,
Mr. Hill was named as Senior Vice President of the Coastal Corporation and President of Coastal States Crude Gathering. In
1971, he began managing Coastal’s NGL business. Previously, Mr. Hill worked for Amoco and Mobil.
Mr. Munch became a director of NuStar GP, LLC in January 2016. He served as General Manager and Head of Corporate &
Investment Banking of Mizuho Bank, Ltd. from 2006 to 2013 and as Deputy General Manager, Origination, of Mizuho Bank,
Ltd. from 2005 to 2006. Prior to his service with Mizuho Bank Ltd., Mr. Munch also served in several senior management
positions with Canadian Imperial Bank of Commerce and CIBC World Markets from 1980 to 2001 and Fidelity Union
Bancorporation (now Wells Fargo) from 1973 to 1980.
Mr. Rosier became a director of NuStar GP, LLC in March 2013. He has been the President and Chief Executive Officer of
McLane Company, Inc., a $44 billion supply chain services company and subsidiary of Berkshire Hathaway, Inc., since
February 1995. Mr. Rosier has been with McLane Company, Inc. since 1984, serving in various senior management positions
prior to his current position. Mr. Rosier also has served as a director of NVR, Inc. since December 2008. He was formerly a
director of Tandy Brands Accessories, Inc. from February 2006 to October 2011, serving as the lead director from October 2009
to October 2010.
Ms. Brown became Executive Vice President and Chief Administrative Officer of NuStar GP, LLC and NuStar GP Holdings in
April 2013. She served as Executive Vice President - Administration of NuStar GP, LLC and NuStar GP Holdings from
February 2012 until her promotion in April 2013. Ms. Brown served as Senior Vice President - Administration of NuStar GP,
LLC from April 2008 through February 2012. She served as Senior Vice President - Corporate Communications of NuStar GP,
LLC from April 2007 through April 2008. Prior to her service to NuStar GP, LLC, Ms. Brown served as Senior Vice President -
Corporate Communications for Valero Energy from September 1997 to April 2007.
Mr. Shoaf became Executive Vice President and Chief Financial Officer of NuStar GP, LLC and NuStar GP Holdings in
January 2014. He served as Senior Vice President and Controller of NuStar GP, LLC and NuStar GP Holdings from February
2012 until his promotion in January 2014. Mr. Shoaf served as Vice President and Controller of NuStar GP, LLC from July
2005 to February 2012 and Vice President and Controller of NuStar GP Holdings from March 2006 until February 2012. He
served as Vice President - Structured Finance for Valero Corporate Services Company, a subsidiary of Valero Energy, from
2001 until joining NuStar GP, LLC.
Mr. del Alamo became Senior Vice President and Controller of NuStar GP, LLC and NuStar GP Holdings in July 2014. Prior
thereto, he served as Vice President and Controller of NuStar GP, LLC and NuStar GP Holdings since January 2014. He served
as Vice President and Assistant Controller of NuStar GP, LLC from July 2010 until his promotion in January 2014. From April
2008 to July 2010 he served as Assistant Controller of NuStar GP, LLC. Prior to his service at NuStar GP, LLC, Mr. del Alamo
served as Director-Sarbanes Oxley Compliance for Valero Energy.
Ms. Perry became Senior Vice President, General Counsel-Corporate & Commercial Law and Corporate Secretary of NuStar
GP, LLC and NuStar GP Holdings in January 2014. She served as Vice President, Assistant General Counsel and Corporate
Secretary of NuStar GP, LLC and as Corporate Secretary of NuStar GP Holdings from February 2010 until her promotion in
January 2014. From June 2005 to February 2010 she served as Assistant General Counsel and Assistant Secretary of NuStar
GP, LLC and, from March 2006 to February 2010, Assistant Secretary of NuStar GP Holdings. Prior to her service at NuStar
GP, LLC, Ms. Perry served as Counsel to Valero Energy.
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Ms. Thompson became Senior Vice President, General Counsel-Litigation, Regulatory & Environmental of NuStar GP, LLC
and NuStar GP Holdings in January 2014. She served as Vice President, Assistant General Counsel and Assistant Secretary of
NuStar GP, LLC from February 2010 until her promotion in January 2014. From May 2007 to February 2010 she served as
Assistant General Counsel and Assistant Secretary of NuStar GP, LLC. Prior to her service at NuStar GP, LLC, Ms. Thompson
served as Managing Counsel to Valero Energy.
SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE
Section 16(a) of the Exchange Act requires directors, executive officers and persons who beneficially own more than 10% of
NuStar Energy’s equity securities to file certain reports with the Securities and Exchange Commission (SEC) concerning their
beneficial ownership of NuStar Energy’s equity securities. We believe that our directors, executive officers and greater than
10% unitholders have filed all Section 16(a) reports by the applicable deadlines with respect to the year ended December 31,
2016, other than one late Form 5 by Ms. Perry with respect to a gift of units during 2015 and one late Form 4 by Mr. Shoaf with
respect to the receipt of units and the withholding of units to satisfy taxes in connection with the vesting of an incentive award
during 2016.
CODE OF ETHICS OF SENIOR FINANCIAL OFFICERS
NuStar GP, LLC has adopted a Code of Ethics for Senior Financial Officers that applies to NuStar GP, LLC’s principal
executive officer, principal financial officer and controller. This code charges the senior financial officers with responsibilities
regarding honest and ethical conduct, the preparation and quality of the disclosures in documents and reports we file with or
submit to the SEC, compliance with applicable laws, rules and regulations, adherence to the code and reporting of violations of
the code.
AUDIT COMMITTEE
CORPORATE GOVERNANCE
The Audit Committee reviews and reports to the Board on various auditing and accounting matters, including the quality,
objectivity and performance of NuStar Energy’s internal and external accountants and auditors, the adequacy of its financial
controls and the reliability of financial information reported to the public. The Audit Committee also monitors NuStar Energy’s
compliance with environmental laws and regulations. The Board has adopted a written charter for the Audit Committee, a copy
of which is available on NuStar Energy’s website at www.nustarenergy.com. The members of the Audit Committee are Mr.
Bates (Chairman), Mr. Hill, Mr. Munch and Mr. Rosier. The Board has determined that Mr. Bates is an “audit committee
financial expert” (as defined by the SEC), and that each member of the Audit Committee is “independent” as that term is used
in the NYSE Listing Standards and described below in Item 13. The Audit Committee met eight times during 2016. For further
information, see the Audit Committee Report below.
AUDIT COMMITTEE REPORT
Management of NuStar GP, LLC is responsible for NuStar Energy’s internal controls and the financial reporting process.
KPMG LLP (KPMG), NuStar Energy’s independent registered public accounting firm for the year ended December 31, 2016,
is responsible for performing an independent audit of NuStar Energy’s consolidated financial statements in accordance with the
standards of the Public Company Accounting Oversight Board (PCAOB) and generally accepted auditing standards, and an
audit of NuStar Energy’s internal control over financial reporting in accordance with the standards of the PCAOB, and issuing a
report thereon. The Audit Committee monitors and oversees these processes and approves the selection and appointment of
NuStar Energy’s independent registered public accounting firm and recommends the ratification of such selection and
appointment to the Board.
The Audit Committee has reviewed and discussed NuStar Energy’s audited consolidated financial statements with management
and KPMG. The Audit Committee has discussed with KPMG the matters required to be discussed by Auditing Standard 1301,
“Communications with Audit Committees,” issued by the PCAOB. The Audit Committee has received written disclosures and
the letter from KPMG required by applicable requirements of the PCAOB concerning independence and has discussed with
KPMG its independence.
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Based on the foregoing review and discussions and such other matters the Audit Committee deemed relevant and appropriate,
the Audit Committee recommended to the Board that the audited consolidated financial statements of NuStar Energy be
included in NuStar Energy’s Annual Report on Form 10-K for the year ended December 31, 2016.
Members of the Audit Committee:
J. Dan Bates (Chairman)
Dan J. Hill
Robert J. Munch
W. Grady Rosier
RISK OVERSIGHT
Although it is the job of management to assess and manage our risk, the Board of Directors and its Audit Committee (each
where applicable) discuss the guidelines and policies that govern the process by which risk assessment and management is
undertaken and evaluate reports from various functions with the management team on risk assessment and management. The
Board interfaces regularly with management and receives periodic reports that include updates on operational, financial, legal
and risk management matters. The Audit Committee assists the Board in oversight of the integrity of NuStar Energy’s financial
statements and NuStar Energy’s compliance with legal and regulatory requirements, including those related to the health, safety
and environmental performance of our company. The Audit Committee also reviews and assesses the performance of NuStar
Energy’s internal audit function and its independent auditors. The Board receives regular reports from the Audit Committee.
For a description of our oversight and evaluation of compensation risk, see “Evaluation of Compensation Risk” in Item 11
below.
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ITEM 11. EXECUTIVE COMPENSATION
COMPENSATION COMMITTEE
The Compensation Committee reviews and reports to the Board on matters related to compensation strategies, policies and
programs, including certain personnel policies and policy controls, management development, management succession and
benefit programs. The Compensation Committee also approves and administers NuStar Energy’s equity compensation plans
and incentive bonus plan. The Board has adopted a written charter for the Compensation Committee, a copy of which is
available on NuStar Energy’s website at www.nustarenergy.com. The members of the Compensation Committee are Mr. Hill
(Chairman), Mr. Bates, Mr. Munch and Mr. Rosier, none of whom is a current or former employee or officer of NuStar GP,
LLC and each of whom has been determined by the Board to be “independent,” as described below in Item 13. The
Compensation Committee met four times during 2016.
COMPENSATION COMMITTEE REPORT
The Compensation Committee has reviewed and discussed the Compensation Discussion and Analysis with management.
Based on its review and discussion and such other matters the Compensation Committee deemed relevant and appropriate,
the Compensation Committee recommended to the Board that the Compensation Discussion and Analysis be included in this
Annual Report on Form 10-K.
Members of the Compensation Committee:
Dan J. Hill (Chairman)
J. Dan Bates
Robert J. Munch
W. Grady Rosier
EXECUTIVE COMPENSATION PHILOSOPHY
COMPENSATION DISCUSSION AND ANALYSIS
Our philosophy for compensating our named executive officers (NEOs) is based on the belief that a significant portion of
executive compensation should be incentive-based and determined by both the performance of NuStar Energy and the
executive’s individual performance objectives. Our executive compensation programs are designed to accomplish the
following long-term objectives:
•
•
•
•
•
increase value to unitholders, while practicing good corporate governance;
support our business strategy and business plan by clearly communicating what is expected of executives with
respect to goals and results;
provide the Compensation Committee with the flexibility to respond to the continually changing environment in
which NuStar Energy operates;
align executive incentive compensation with NuStar Energy’s short- and long-term performance results; and
provide market-competitive compensation and benefits to enable us to recruit, retain and motivate the executive
talent necessary to produce sustainable growth for our unitholders.
Compensation for our NEOs primarily consists of base salary, an annual incentive bonus and long-term, equity-based
incentives, which we refer to as “Total Direct Compensation.” Our NEOs participate in the same group benefit programs
available to our salaried employees in the United States. In addition, as discussed under “Post-Employment Benefits” below,
our NEOs may participate in certain non-qualified, retirement-related programs. Our NEOs do not have employment or
severance agreements, other than the change of control severance agreements described under “Potential Payments Upon
Termination or Change of Control” in this Item 11. The Compensation Committee targets base salary for our NEOs, as well
as annual incentive bonus and long-term incentive opportunities (expressed, in each case, as a percentage of base salary),
with reference to prevailing practices of our peer companies and information from survey sources. Each NEO’s incentive
bonus is awarded in accordance with the same bonus plan and metric that we use for each of our other employees. In
determining total compensation, as well as each component thereof, we consider the unique responsibilities of each
individual’s position, as well as his or her experience and performance, together with the market information.
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Our NEOs for the year ended December 31, 2016 were:
• Bradley C. Barron, President and Chief Executive Officer (CEO);
• Thomas R. Shoaf, Executive Vice President and Chief Financial Officer;
• Mary Rose Brown, Executive Vice President and Chief Administrative Officer;
• Amy L. Perry, Senior Vice President, General Counsel-Corporate and Commercial Law & Corporate Secretary; and
• Karen M. Thompson, Senior Vice President & General Counsel-Litigation, Regulatory and Environmental.
ADMINISTRATION OF EXECUTIVE COMPENSATION PROGRAMS
Our executive compensation programs are administered by our Board’s Compensation Committee. The Compensation
Committee is composed of independent directors who are not participants in our executive compensation programs. Policies
adopted by the Compensation Committee are implemented by our Human Resources department.
The Compensation Committee considers market trends in compensation, including the practices of identified competitors,
and the alignment of the compensation program with NuStar Energy’s strategy. Specifically, for our NEOs, the Compensation
Committee:
•
•
•
•
•
establishes and approves target compensation levels for each NEO;
approves company performance measures and goals;
determines the mix between cash and equity compensation, short-term and long-term incentives and benefits;
verifies the achievement of previously established performance goals; and
approves the resulting cash or equity awards to our NEOs.
In making determinations about Total Direct Compensation for our NEOs, the Compensation Committee takes into account a
number of factors, including:
•
•
•
the competitive market for talent;
compensation paid at peer companies;
industry-wide trends;
• NuStar Energy’s performance;
•
•
the particular NEO’s role, responsibilities, experience and performance; and
retention.
The Compensation Committee also considers other equitable factors such as the role, contribution and performance of an
individual relative to his or her peers at the company. The Compensation Committee does not assign specific weight to these
factors, but rather makes a subjective judgment taking all of these factors into account.
The Compensation Committee retained BDO USA, LLP (BDO) as its independent compensation consultant for expertise and
guidance with respect to executive compensation matters. In its role as advisor to the Compensation Committee, BDO was
retained directly by the Compensation Committee, which has the authority to select, retain and/or terminate its relationship
with a consulting firm. The Compensation Committee determined that there are no conflicts of interest between the company,
the Compensation Committee and BDO because BDO provides no other services to NuStar Energy; fees paid to BDO
represent less than a fraction of 1% of BDO’s worldwide revenues; BDO has policies in place to prevent a conflict of interest,
including a policy that no employee of BDO may own NuStar Energy units; and there is no business or personal relationship
between BDO’s consultant and any of NuStar Energy’s officers or directors.
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Selection of Compensation Comparative Data
The Compensation Committee has historically relied upon two primary sources of data in developing competitive market
reference points for base salaries and annual incentive and long-term incentive targets: a group of master limited partnerships
(MLPs) and other companies in our industry and broader survey data on comparably sized entities.
To establish compensation for each of the NEOs, the Compensation Committee consults with management and BDO and
considers compensation provided by certain peer companies when evaluating competitive levels of compensation. During
2014, after we sold our remaining 50% interest in the asphalt business, the Compensation Committee, in consultation with
management and BDO, reevaluated our peer group in view of those changes and removed the independent refining
companies that were previously included in our peer group. Since July 2014, our peer group (the Compensation Comparative
Group) has been composed entirely of MLPs against which we believe we compete for executive talent. The competitive data
regarding the companies in the Compensation Comparative Group is derived from their respective publicly filed annual
proxy statements or Annual Reports on Form 10-K.
Since the Compensation Committee approved the Compensation Comparative Group in July 2014, several of the companies
on the list have been, or are in the process of, merging or consolidating. The table below lists the companies in the
Compensation Comparative Group after giving effect to all such transactions that have closed prior to February 20, 2017,
with the relevant transactions described in the footnotes following the table.
Company (1)
1. Arc Logistics Partners LP
2. Boardwalk Pipeline Partners, LP
3. Buckeye Partners, L.P.
4. Enable Midstream Partners, LP
5. Enbridge Energy Partners, L.P.
6. Energy Transfer Partners, L.P. (2)
7. EnLink Midstream Partners, LP
8. Enterprise Products Partners L.P.
9. Genesis Energy, L.P.
10. Holly Energy Partners, L.P.
11. Magellan Midstream Partners, L.P.
12. MPLX LP
13. Phillips 66 Partners LP
14. Plains All American Pipeline, L.P.
15. Sunoco Logistics Partners L.P. (2)
16. Tesoro Logistics LP
17. Valero Energy Partners LP
18. Western Refining Logistics, LP
Ticker
ARCX
BWP
BPL
ENBL
EEP
ETP
ENLK
EPD
GEL
HEP
MMP
MPLX
PSXP
PAA
SXL
TLLP
VLP
WNRL
(1) The following companies have been removed from the Compensation Comparative Group originally established in July
2014 as a result of the transactions described in this footnote: Access Midstream Partners, L.P. merged with Williams
Partners L.P. in February 2015; Atlas Pipeline Partners, L.P. was acquired by Targa Resources Partners LP in February
2015; Kinder Morgan Energy Partners, L.P. was acquired by Kinder Morgan, Inc. in November 2014; MarkWest Energy
Partners, L.P. was acquired by MPLX LP in December 2015; Regency Energy Partners LP was acquired by Energy
Transfer Partners, L.P. in April 2015; and Targa Resources Partners LP was acquired by Targa Resources Corp. in
February 2016.
(2) On November 21, 2016, Sunoco Logistics Partners L.P. (SXL) and Energy Transfer Partners, L.P. (ETP) announced that
they have entered into a merger agreement providing for the acquisition of ETP by SXL.
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Periodically, at the Compensation Committee’s request, BDO reviews survey data reported on a position-by-position basis to
obtain additional information regarding compensation of comparable positions. The survey data consists of general industry
data for specific executive positions reported in certain Towers Watson and other published executive compensation surveys.
We refer to the competitive survey data, together with the Compensation Comparative Group data, as the “Compensation
Comparative Data.”
Process and Timing of Compensation Decisions
The Compensation Committee reviews and approves all compensation of the NEOs. The CEO develops recommendations
for the compensation of the other NEOs in consultation with our Human Resources department and with BDO. In making
these recommendations, the CEO considers the Compensation Comparative Data and evaluates the individual performance of
each NEO and their respective contributions to NuStar Energy. The recommendations are then reviewed by the
Compensation Committee, which may accept the recommendations or may make adjustments to the recommended
compensation based on the Compensation Committee’s assessment of the individual’s performance and contributions to
NuStar Energy.
As required by the Compensation Committee’s charter, the CEO’s compensation is reviewed and approved by the
Compensation Committee based on the Compensation Comparative Data and the Compensation Committee’s independent
evaluation of the CEO’s contributions to NuStar Energy’s performance.
Each July, the Compensation Committee reviews each NEO’s Total Direct Compensation, including base salary and the
target levels of annual incentive and long-term incentive compensation. The annual review includes an evaluation of the Total
Direct Compensation of the NEOs from an internal equity perspective and a review of reports on the compensation history of
each NEO. The Compensation Committee also periodically reviews competitive market data provided by BDO. Based on
these reviews and evaluations, the Compensation Committee establishes annual salary rates for each NEO for the upcoming
12-month period and sets target levels of annual incentive and long-term incentive compensation. Although the target levels
are established in July, the long-term incentives are reviewed again at the time of grant, typically in the fourth quarter for
restricted units and in the first quarter for performance units. The Compensation Committee also may review salaries or grant
long-term incentive awards at other times during the year because of new appointments, promotions or other extraordinary
circumstances.
The following table summarizes the typical timing of some of our significant compensation events.
Event
- Establish financial performance objectives for the current year’s annual incentive bonus
- Evaluate achievement of the bonus metric for the prior year
- Review and certify prior year financial performance for performance units
- Grant performance units for the current year
- Review NEO base salaries and targets for annual incentive bonus and long-term incentive
grants for the current year
- Grant restricted units to employees, including the NEOs
- Grant restricted units to non-employee directors pursuant to the director compensation
program
- Set meeting dates for action by the Compensation Committee for the upcoming year
Timing
First quarter
Third quarter
Fourth quarter
Additional information regarding the timing of the 2016 long-term incentive grants is discussed below under “Restricted
Units” and “Performance Units.”
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ELEMENTS OF EXECUTIVE COMPENSATION
Compensation for our NEOs primarily consists of the following elements, which we refer to as Total Direct Compensation:
Element
Form
Purpose
Fixed
Base Salary
Cash
- Foundation of the executive compensation program
- Provides a fixed level of competitive pay
- Reflects the individual’s primary duties and
responsibilities
- Foundation for incentive opportunities and benefit
levels
At-Risk Annual Incentive Bonus
Cash
- Focus NEOs on improving distributable cash flow
At-Risk
Long-Term Equity-Based
Incentives:
- Restricted Units
- Performance Units
Units
- Directly tie NEO financial reward opportunities with
the rewards to unitholders, as measured by long-term
unit price performance and payment of distributions
- Time-vesting award focused on retention and
increasing ownership levels
- Performance-vesting award focused on attainment of
objective performance measure
We also offer group medical and other insurance benefits to provide our employees (including our NEOs) affordable
coverage at group rates, as well as pension benefits that reward continued service and a thrift plan that provides a tax-
advantaged savings opportunity.
Relative Size of Primary Elements of Compensation
In setting compensation, the Compensation Committee considers the aggregate amount of compensation payable to each
NEO and the form of the compensation. The Compensation Committee seeks to achieve the appropriate balance between
salary, cash rewards earned for the achievement of company and personal objectives, and long-term incentives that align the
interests of our NEOs with those of our unitholders. The size of each element is based on competitive market practices, as
well as company and individual performance.
As illustrated by the table below, the level of at-risk incentive compensation typically increases in relation to an NEO’s
responsibilities, with the level of incentive compensation for more senior executive officers being a greater percentage of
Total Direct Compensation than for less senior executives. The Compensation Committee believes that tying a significant
portion of an NEO’s incentive compensation to NuStar Energy’s performance more closely aligns the NEO’s interests with
those of our unitholders.
Name
Barron
Shoaf
Brown
Perry
Thompson
Target Percentage of Total Direct Compensation
Annual
Incentive Bonus (%)
25
19
19
22
22
Long-Term
Incentives (%)
50
48
48
39
39
Base Salary (%)
25
32
32
39
39
TOTAL (%) (1)
100
100
100
100
100
(1) The sum of Base Salary, Annual Incentive Bonus and Long-Term Incentive percentages may vary slightly from 100%
due to rounding.
Because we place such a large proportion of our Total Direct Compensation at risk in the form of variable pay (i.e., annual
and long-term incentives), the Compensation Committee does not adjust current compensation based upon realized gains or
losses from prior incentive awards. For example, we will not reduce the size of a target long-term incentive grant in a
particular year solely because NuStar Energy’s unit price performed well during the immediately preceding years. We believe
that adopting a policy of making such adjustments would penalize management’s current compensation for NuStar Energy’s
prior success.
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Individual Performance and Personal Objectives
The Compensation Committee evaluates our NEOs’ individual performance and personal objectives with input from our
CEO. Our CEO’s performance is evaluated by the Compensation Committee in consultation with other members of the
Board.
Assessment of individual performance may include objective criteria, but is a largely subjective process. The criteria used to
measure an individual’s performance may include use of quantitative criteria (e.g., execution of projects within budget,
improving an operating unit’s profitability, or timely completion of an acquisition or divestiture), as well as more qualitative
factors, such as the NEO’s ability to lead, communicate and successfully adhere to NuStar’s core values (i.e., environmental
and workplace safety, integrity, work commitment, effective communication and teamwork). There are no specific weights
given to any of these various elements of individual performance.
The Compensation Committee uses its evaluation of individual performance to supplement the objective compensation
criteria and adjust an NEO’s recommended compensation. For example, although an individual’s indicated bonus may be
calculated to be $100,000 based on NuStar Energy’s performance, the individual’s performance evaluation might result in a
reduction or increase in that amount.
Base Salaries
The Compensation Committee reviews the base salaries for our NEOs annually based on recommendations of our CEO, with
input from BDO and our Human Resources department. Our CEO’s base salary is reviewed and approved by the
Compensation Committee based on its review of recommendations by BDO, our Chairman and our Human Resources
department.
The competitiveness of base salaries for each NEO’s position is determined by an evaluation of the compensation data
described above. Base salaries may be adjusted to achieve what is determined to be a reasonably competitive level or to
reflect promotions, the assignment of additional responsibilities, individual performance or the performance of NuStar
Energy. Salaries are also periodically adjusted to remain competitive with the Compensation Comparative Data.
On January 1, 2014, Mr. Barron, Mr. Shoaf, Ms. Perry and Ms. Thompson were promoted to their current positions. Based on
recommendations from BDO, the Chairman (in the case of the CEO’s base salary) and the CEO (in the case of the base
salaries for Mr. Shoaf, Ms. Perry and Ms. Thompson), the Compensation Committee raised the base salaries of each of Mr.
Barron, Mr. Shoaf, Ms. Perry and Ms. Thompson effective January 1, 2014 to reflect their respective promotions and
increased responsibilities. In July 2014, BDO performed a comprehensive review of our NEOs’ Total Direct Compensation.
Effective July 1, 2014, after consultation with BDO, the Chairman (in the case of the CEO’s base salary) and the CEO (in the
case of the base salaries for each other NEO), the Compensation Committee raised the base salaries of each of the NEOs to
remain competitive with the Compensation Comparative Data.
Due to the extensive analysis performed by BDO in July 2014, the Compensation Committee did not request that BDO
provide an updated detailed analysis for 2015 or 2016. For 2015 and 2016, the Committee considered, among other factors,
the Consumer Price Index, the average base salary increase anticipated by nationwide compensation surveys, the increases
required by NuStar Energy’s union contracts and the anticipated increases by other local companies. After consideration of
these factors and consultation with BDO, the Chairman (in the case of the CEO’s base salary) and the CEO (in the case of the
base salaries for each other NEO), the Compensation Committee raised the base salaries of each of the NEOs effective on
each of July 1, 2015 and July 1, 2016 to remain competitive. The July 1, 2016 increases and the December 31, 2016 base
salaries for each of the NEOs are presented in the table below.
Name
Annualized Base Salary at
December 31, 2016 ($)
July 1, 2016 Increase to Prior
Annualized Salary ($)
Barron
Shoaf
Brown
Perry
Thompson
575,000
349,700
376,700
275,800
275,800
35,000
10,200
11,000
8,000
8,000
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Annual Incentive Bonus
Our NEOs participate in the same annual incentive program in which all domestic company employees participate. Under our
annual bonus plan, participants can earn annual incentive bonuses based on the following three factors:
• The individual’s position, which is used to determine a targeted percentage of annual base salary that may be
awarded as incentive bonus. Generally, the target amount for the NEOs is set following the analysis of market
practices in the Compensation Comparative Group with reference to the median bonus target available to
comparable executives in those companies;
• NuStar Energy’s attainment of specific quantitative financial goals, which are established by the Compensation
Committee during the first quarter of the year; and
• A discretionary evaluation by the Compensation Committee of both NuStar Energy’s performance and, in the case
of the NEOs, the individual’s performance.
In July 2014, following BDO’s comprehensive review of our NEOs’ Total Direct Compensation and after consultation with
BDO and the CEO, the Compensation Committee raised the annual incentive bonus targets for Ms. Perry and Ms. Thompson
from 50% to 55%. In July 2015, after consultation with BDO and the Chairman, the Compensation Committee raised the
annual incentive bonus target for Mr. Barron from 90% to 100%. The Compensation Committee did not make any changes
to the annual incentive bonus targets for any of the NEOs during 2016.
The following table shows each NEO’s annual incentive bonus target for the fiscal year ended December 31, 2016 (expressed
as a percent of base salary paid).
Name
Barron
Shoaf
Brown
Perry
Thompson
Annual Incentive Bonus Target
(% of base salary paid)
100
60
60
55
55
Determination of Annual Incentive Target Opportunities
As illustrated in the table above, each NEO has an annual incentive opportunity generally based on a stated percentage of his
or her salary paid that year. The target amount is awarded for achieving a 100% score on our stated financial goal under the
annual bonus plan. For example, in a year with a 100% score, an NEO paid $200,000 with a target annual incentive
opportunity equal to 60% of his eligible earnings would receive a bonus of $120,000.
Once the financial goals have been reviewed and measured, the Compensation Committee has the authority to exercise its
discretion in evaluating NuStar Energy’s performance. In exercising this discretionary judgment, the Compensation
Committee considers such relevant performance factors as growth, attainment of strategic objectives, acquisitions and
divestitures, safety and environmental compliance, as well as other considerations. This discretionary judgment may result in
an increase or decrease to the aggregate earned award for all employees that is based upon the attainment of NuStar Energy’s
financial goals.
The CEO develops individual incentive bonus recommendations for the other NEOs based upon the methodology described
above. In addition, both the CEO and the Compensation Committee may make adjustments to the recommended incentive
bonus amounts based upon an assessment of an individual’s performance and contributions to NuStar Energy. The CEO and
the Compensation Committee also review and discuss each NEO’s bonus on a case-by-case basis, considering such factors as
teamwork, leadership, individual accomplishments and initiative, and may adjust the bonus awarded to a specific NEO to
reflect these factors.
The bonus target for the CEO is decided solely by the Compensation Committee, and the Compensation Committee may
make discretionary adjustments to the calculated level of bonus for the CEO based upon its independent evaluation of the
CEO’s performance and contributions.
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Company Performance Objectives
For 2016, as in prior years, our annual incentive bonus is designed to focus our NEOs on improving NuStar Energy’s
distributable cash flow (DCF), a non-GAAP measure of financial performance. In the MLP investment community, DCF is
widely regarded as a significant determinant of operating performance. As such, the Compensation Committee believes the
measure appropriately aligns our management’s interest with our unitholders’ interest in increasing distributions in a prudent
manner. The Compensation Committee approved NuStar Energy’s bonus metric based on management’s recommendations
and input from BDO.
We derive DCF from our financial statements by adjusting our net income for depreciation and amortization expense,
unrealized gains and losses arising from certain derivative contracts and other non-cash items, including non-cash gains or
losses or impairment charges. We further adjust our earnings by (1) subtracting our aggregate annual reliability capital
expenditures, (2) adding non-cash unit-based compensation expenses for awards that we intend to satisfy with the issuance of
units upon vesting and (3) adding or subtracting, as applicable, certain cash receipts and disbursements not included in net
income.
Each year, the Compensation Committee establishes a target distribution coverage ratio (DCR) for NuStar Energy to achieve
for the year and establishes corresponding levels of performance for which the incentive opportunity would be paid. DCR is
a non-GAAP measure determined by dividing DCF applicable to common limited partners by the distributions applicable to
common limited partners. The Compensation Committee has discretion to raise or lower the incentive opportunity resulting
from this calculation by 25%. In addition, the budgeted DCF may be adjusted during the year in order to account for
acquisitions or other significant changes not anticipated at the time the target was determined. For 2016, the Compensation
Committee determined that a bonus pool for all employees would be established based on DCF such that employees would
receive a 100% bonus for 2016 if Nustar Energy achieves a “target” DCR of 1.03 times and a 90% bonus if NuStar Energy
achieves a “threshold” DCR of 1.00 times for 2016, with any DCR between 1.00 and 1.03 times resulting in a bonus
percentage determined through straight line interpolation. A DCR of less than 1.00 times for 2016 would result in a 0%
bonus. After achieving a 100% bonus, incremental DCF earned would be shared between the bonus pool and NuStar Energy
until employees achieve a 200% bonus.
Determination of Awards
For the 2016 annual incentive bonus determination, the Compensation Committee reviewed NuStar Energy’s DCF against
the established target of attaining a DCR of 1.03 times and considered the performance of each NEO to determine the amount
of incentive award earned. Based on this review, the Compensation Committee set the bonus award for our NEOs at 125%.
Actual bonuses awarded are shown in the following table and are reported in the “Non-Equity Incentive Plan Compensation”
column of the Summary Compensation Table.
Name
Barron
Shoaf
Brown
Perry
Thompson
Bonuses Paid For 2016 ($)
700,000
260,000
280,000
190,000
190,000
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Long-Term Incentive Awards
We provide unit-based, long-term incentive compensation for employees, including our NEOs, and for our non-employee
directors through our 2000 Long-Term Incentive Plan (as amended and restated from time to time, the 2000 LTIP). On
January 28, 2016, at a special meeting of unitholders, NuStar Energy’s unitholders approved the Fifth Amended and Restated
2000 LTIP. Among other things, the amended 2000 LTIP:
•
•
•
permits common units available for issuance under the 2000 LTIP to be newly issued in addition to outstanding
common units acquired from an affiliate;
has been updated to delete certain obsolete provisions;
has been updated to reflect certain technical changes in tax laws and in accounting; and
• will not terminate until ten years after the new effective date.
The 2000 LTIP provides for unit awards and a variety of unit-based awards, including unit options, restricted units and
performance units. Long-term incentive awards vest over a period determined by the Compensation Committee, with
performance units vesting upon the achievement of an objective performance goal.
Under the design of our long-term incentive awards, each plan participant, including each NEO, is designated a target long-
term incentive award opportunity expressed as a percentage of base salary. This percentage reflects the fair value of the
awards to be granted.
Effective January 1, 2014, the Compensation Committee raised the long-term incentive targets (expressed as a percent of
base salary) for each of Mr. Barron, Mr. Shoaf, Ms. Perry and Ms. Thompson to reflect their respective promotions and
increased responsibilities. After BDO’s comprehensive review of our NEOs’ Total Direct Compensation in July 2014 and
with the recommendations of BDO, the Chairman (in the case of the CEO’s long-term incentive target) and the CEO (in the
case of the long-term incentive targets for each other NEO), the Compensation Committee raised the long-term incentive
target for each of our NEOs in July 2014. The Compensation Committee did not make any changes to the long-term incentive
targets for our NEOs during 2015 or 2016. The following table shows each NEO’s long-term incentive target for 2016
(expressed as a percent of base salary).
Name
Barron
Shoaf
Brown
Perry
Thompson
Long-Term Incentive Target
(% of base salary)
200
150
150
100
100
The Compensation Committee allocates a percentage of long-term incentive award value to performance-based awards and a
percentage to awards that focus on retention and increasing ownership levels of executive officers (including our NEOs).
Since the fourth quarter of 2011, the target levels of long-term incentive award value have been allocated in the following
manner:
•
•
35% performance units; and
65% restricted units.
The Compensation Committee reviews and approves long-term incentive grants for each of the NEOs. The CEO develops
individual grant recommendations for the other NEOs based upon the methodology described above, but both the CEO and
the Compensation Committee may make adjustments to the recommended grants based upon an assessment of an
individual’s performance and contributions to NuStar Energy. Grants to the CEO are decided solely by the Compensation
Committee following the methodology described above, and the Compensation Committee may make discretionary
adjustments to the calculated level of long-term incentives for the CEO based upon its independent evaluation of the CEO’s
performance and contributions.
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Restricted Units
Restricted units comprise approximately 65% of each NEO’s total NuStar Energy long-term incentive target. The
Compensation Committee expects to grant restricted units on an annual basis. The NEOs’ long-term incentive targets include
approximately 70% NuStar Energy restricted units to be granted by the Compensation Committee under the 2000 LTIP and
30% NuStar GP Holdings phantom units (which we refer to as “restricted units” in Part III of this Annual Report on Form 10-
K) to be granted by NuStar GP Holdings’ compensation committee under its long-term incentive plan. In both cases, no units
are issued at the time of grant and the awards represent the right to receive common units upon vesting. The awards are
calculated from an assumed unit value based on the average closing price of the common units for the first 10 business days
of the month prior to the committee meeting at which the awards are to be approved. The restricted units all vest over five
years in equal increments on the anniversary of the grant date, and common unit distribution equivalents are paid in cash
quarterly for all unvested NuStar Energy and NuStar GP Holdings restricted units. Restricted units of NuStar GP Holdings
were introduced into the compensation program in 2008 to reflect the fact that the performance of NuStar GP Holdings is
directly tied to the performance of NuStar Energy since NuStar GP Holdings’ sole asset is its interest in NuStar Energy. As
described under “Accounting Treatment” below, effective March 1, 2016, NuStar GP Holdings retains the expense associated
with the NuStar GP Holdings restricted unit awards. The annual grants of NuStar GP Holdings restricted units, as well as the
annual grants of the NuStar Energy restricted units, were approved in a joint meeting of the Compensation Committee and
the compensation committee of NuStar GP Holdings’ board of directors.
In 2016, the Compensation Committee determined that the grants would be made as soon as administratively practicable and
no earlier than the third business day following our third quarter earnings release. Due to the time required to award and
implement the grants, the 2016 annual grants were not effective until November 16, 2016. The following table sets forth the
restricted units granted to each of our NEOs in 2016.
Name
Barron
Shoaf
Brown
Perry
Thompson
Restricted Units Granted in 2016
NuStar Energy
11,000
4,920
5,300
2,585
2,585
NuStar GP Holdings
9,000
4,040
4,350
2,125
2,125
For more information regarding the 2016 restricted unit grants, see the table entitled “Grants of Plan-Based Awards During
the Year Ended December 31, 2016.”
Performance Units
Performance units comprise approximately 35% of each NEO’s total NuStar Energy long-term incentive target and typically
have been awarded in the first quarter of each year. The number of performance units awarded is determined by multiplying
the annual base salary rate by the long-term incentive target percentage, and then multiplying that product by 35%. That
product is divided by the assumed value of an individual unit, which is the product of (x) the average common unit price for
the period of December 15 through December 31 (using the daily closing prices) and (y) a factor reflecting the risk that the
award might be forfeited.
Performance units are earned only upon NuStar Energy’s achievement of an objective performance measure for the
performance period. The Compensation Committee believes this type of incentive award strengthens the tie between each
NEO’s pay and our financial performance.
Performance Measure for Awards Prior to 2014. For performance units awarded prior to 2014, the objective performance
measure was tied to NuStar Energy’s total unitholder return (TUR) as compared with a specific group of peer companies
during rolling three-year periods that ended on December 31 of each year following the date of grant. Our NEOs earned 0%,
50%, 100% or 150% of that portion of the initial grant amount that was eligible for vesting, depending upon whether our
TUR was in the last, third, second or first quartile, respectively, and they earned 200% if we ranked highest in the group.
Amounts not earned in a given performance period could be carried forward for one additional performance period and up to
100% of the carried amount could still be earned, depending upon the quartile achieved for that subsequent period.
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On January 29, 2015, the Compensation Committee met and discussed NuStar Energy’s performance for the performance
period ended December 31, 2014, and determined that NuStar Energy’s TUR was in the third quartile of its peer group for
that three-year performance period. As a result, the performance units granted in 2011, 2012 and 2013 that were available to
vest for the performance period ending on December 31, 2014 vested at 50%, in accordance with the award terms. On
January 28, 2016, the Compensation Committee met and discussed NuStar Energy’s performance for the performance period
ended December 31, 2015, and determined that NuStar Energy’s TUR was in the second quartile of its peer group for that
three-year performance period. As a result, the performance units awarded in 2012 and 2013 that were available to vest for
the performance period ending on December 31, 2015 vested at 100%, in accordance with the award terms.
Current Performance Measure. The Compensation Committee delayed consideration of the annual performance unit awards
for 2014 until completion of BDO’s comprehensive review of our NEOs’ Total Direct Compensation in July 2014. After
consultation with BDO and management, the Compensation Committee adopted a different performance measure for
performance unit awards. Beginning with the 2014 performance unit awards, the target performance measure for
performance unit awards has been NuStar Energy achieving a specific DCR, after taking into account the aggregate expense
of the performance units. BDO’s review reflected the fact that cash flow metrics are the most common measures that MLPs
use to determine the vesting of performance unit awards. In addition, as described above, in the MLP investment community,
distribution coverage is widely regarded as a significant determinant of operating performance. The Compensation
Committee believes that distribution coverage appropriately aligns our NEOs’ interest with our unitholders’ interest in
increasing distributions in a prudent manner over time.
Performance units are awarded pursuant to the 2000 LTIP, with each award subject to vesting in three annual increments (or
tranches), based upon our DCR during the one-year performance periods that end on December 31 of each year following the
date of grant, as illustrated in the table below.
Annual Performance Target
2014 Award Tranche Eligible to Vest
2015 Award Tranche Eligible to Vest
2016 Award Tranche Eligible to Vest
Performance Achieved for One-Year Performance Period
2014
Target=
DCR
1.00 : 1
2015
Target=
DCR
1.01 : 1
2016
Target=
DCR
1.03 : 1
1st
N/A
2nd
1st
3rd
2nd
N/A
N/A
1.00 : 1 1.11 : 1 1.07 : 1
1st
Percent of Eligible Units Vested for One-Year Performance Period
100% 200% 150%
Eligible performance units will not vest and will be forfeited if the DCR for the performance period is less than 1.00:1. If the
DCR falls between the benchmarks established by the Compensation Committee for the performance period, the percentage
vesting with respect to performance during that period will be determined through straight-line interpolation. The
Compensation Committee retains the full discretion to vest up to 200% of performance units available for vesting, regardless
of the DCR that NuStar Energy attains for the applicable performance period. Additional information is provided below
regarding the performance targets established by the Compensation Committee and the performance attained by NuStar
Energy for each of the 2014, 2015 and 2016 performance periods.
•
•
2014 Performance Period. In July 2014, the Compensation Committee determined that the target performance
measure for the 2014 performance unit awards would be NuStar Energy achieving a DCR of 1.00:1 for 2014 and
that the target measure for performance unit vesting with respect to 2015 and each year thereafter would be the DCR
determined by the Compensation Committee in the first quarter of the year, based on the approved budget for that
year. On January 29, 2015, the Compensation Committee determined that NuStar Energy achieved a DCR of 1.00:1
for 2014 and, in accordance with the award terms, the tranche of performance units available to vest for the 2014
awards vested at 100%.
2015 Performance Period. The target measure established by the Compensation Committee on January 29, 2015 for
performance unit vesting with respect to 2015 performance was NuStar Energy achieving a DCR of 1.01:1, with all
units eligible for vesting as follows based on the DCR for 2015:
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Level
Below Threshold
Threshold
Target
Exceeds Target
Maximum
DCR
% Performance Units Earned
Below 1.00 : 1
1.00 : 1
1.01 : 1
1.05 : 1
1.10 : 1
0%
90%
100%
150%
200%
On January 28, 2016, the Compensation Committee determined that NuStar Energy achieved a DCR of 1.11:1 for
2015 and, in accordance with the award terms, the performance units available to vest under the applicable tranche
for each of the 2014 awards and 2015 awards with respect to 2015 performance vested at 200%.
•
2016 Performance Period. On February 24, 2016, the Compensation Committee awarded the target number of
performance units set forth below to our NEOs:
Name
Barron
Shoaf
Brown
Perry
Thompson
Performance Units Awarded in 2016
13,221
6,234
6,714
3,279
3,279
The target measure established by the Compensation Committee on February 24, 2016 for performance unit vesting
with respect to 2016 performance was NuStar Energy achieving a DCR of 1.03:1, with all units eligible for vesting
as follows based on the DCR for 2016:
Level
Below Threshold
Threshold
Target
Exceeds Target
Maximum
DCR
% Performance Units Earned
Below 1.00 : 1
1.00 : 1
1.03 : 1
1.07 : 1
1.12 : 1
0%
90%
100%
150%
200%
On January 26, 2017, the Compensation Committee determined that NuStar Energy achieved a DCR of 1.07:1 for
2016 and, in accordance with the award terms, the performance units available to vest under the applicable tranche
for each of the 2014 awards, 2015 awards and 2016 awards with respect to 2016 performance vested at 150%. See
the table entitled “Grants of Plan-Based Awards During the Year Ended December 31, 2016.”
Perquisites and Other Benefits
Perquisites
We provide only minimal perquisites to our NEOs. Each of our NEOs received federal income tax preparation services and
personal liability insurance in 2016. For more information on perquisites, see the Summary Compensation Table and its
footnotes.
Other Benefits
We provide other benefits, including medical, life, dental and disability insurance in line with competitive market conditions.
Our NEOs are eligible for the same benefit plans provided to our other employees, including our pension plans, 401(k) thrift
plan (the Thrift Plan), and insurance and supplemental plans chosen and paid for by employees who desire additional
coverage. Our NEOs and other employees whose compensation exceeds certain limits are eligible to participate in non-
qualified excess benefit programs whereby those individuals can choose to make larger contributions than allowed under the
qualified plan rules and receive correspondingly higher benefits. These plans are described below under “Post-Employment
Benefits.”
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Post-Employment Benefits
Pension Plans
For a discussion of our Pension Plan, as well as the Excess Pension Plan, please see the narrative description accompanying
the table entitled “Pension Benefits for the Year Ended December 31, 2016.”
Nonqualified Deferred Compensation Plan (Excess Thrift Plan)
The Excess Thrift Plan provides unfunded benefits to those employees whose annual additions under the Thrift Plan are
subject to the limitations under §415 of the Internal Revenue Code of 1986, as amended (the Code), and/or who are
constrained from making maximum contributions under the Thrift Plan by §401(a)(17) of the Code, which limits the amount
of an employee’s annual compensation that may be taken into account under that plan. The Excess Thrift Plan is comprised
of two separate components, consisting of (1) an “excess benefit plan” as defined under §3(36) of The Employee Retirement
Income Security Act of 1974, as amended (ERISA), and (2) a plan that is maintained primarily for the purpose of providing
deferred compensation for a select group of management or highly compensated employees. Each component of the Excess
Thrift Plan consists of a separate plan for purposes of Title I of ERISA. To the extent a participant’s annual total
compensation exceeds the compensation limits for the calendar year under §401(a)(17) of the Code ($265,000 for 2016), the
participant’s Excess Thrift Plan account is credited with that number of hypothetical NuStar Energy units that could have
been purchased with the difference between:
• The total company matching contributions that would have been credited to the participant’s account under the
Thrift Plan had the participant’s contributions not been reduced pursuant to §401; and
• The actual company matching contributions credited to such participant’s account.
Mr. Barron, Mr. Shoaf, Ms. Brown and Ms. Perry participated in the Excess Thrift Plan in 2016.
Change of Control Severance Arrangements
We initially entered into change of control severance agreements with each of our NEOs in, or prior to, 2007. The change of
control severance agreements are intended to ensure the continued availability of these executives in the event of certain
transactions culminating in a “change of control” as defined in the agreements. The change of control severance agreements
have three-year terms and are automatically extended for one year upon each anniversary unless we give notice not to extend.
If a “change of control” (as defined in the agreements) occurs during the term of an agreement, then the agreement becomes
operative for a fixed three-year period. The agreements provide generally that the NEO’s terms and conditions of
employment (including position, location, compensation and benefits) will not be adversely changed during the three-year
period after a change of control.
The agreements contain tiers of compensation and benefits based on each NEO’s position, with each tier corresponding to a
certain severance multiple used to calculate total compensation and benefits to be provided under the agreements.
Compensation and benefits under the agreements are triggered upon the occurrence of any of the following in connection
with a change of control:
•
•
•
•
termination of employment by the employer other than for “cause” (as defined in the agreements), death or
disability;
termination by the NEO for “good reason” (as defined in the agreements);
termination by the NEO other than for “good reason;” and
termination of employment because of death or disability.
These triggers were designed to ensure the continued availability of these executives following a change of control, and to
compensate them at appropriate levels if their employment is unfairly or prematurely terminated during the applicable term
following a change of control.
We amended and restated the change of control severance agreements on August 1, 2016 to:
•
•
•
•
reflect NuStar Services Company LLC, our wholly owned subsidiary (NuStar Services Co), as the employer;
create a new tier and corresponding severance multiple for Executive Vice Presidents (of which we had none when
the previous agreements were adopted);
align each NEO with the applicable severance multiple to reflect each NEO’s promotions and associated changes in
position since entering into the previous agreements;
add a requirement that the NEO execute a release of claims against NuStar Energy, NuStar Services Co and
affiliated companies (as defined in the agreements) in order to be eligible to retain compensation and benefits
provided under the agreements; and
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•
reflect legal developments since the previous agreements.
The following table sets forth the severance multiple applicable to each NEO, based on his or her current officer position.
Name
Applicable Officer Position
Severance Multiple
Barron
Shoaf
Brown
Perry
Thompson
Chief Executive Officer
Executive Vice President
Executive Vice President
Senior Vice President
Senior Vice President
3
2.5
2.5
2
2
When determining the amounts and benefits payable under the agreements, the Compensation Committee sought to secure
compensation that is competitive in our market in order to recruit and retain executive officer talent. Consideration was given
to the principal economic terms found in written employment and change of control agreements of other publicly traded
companies. For more information regarding payments and benefits that may be provided under our change of control
severance arrangements, see our disclosures below under the caption “Potential Payments upon Termination or Change of
Control.”
Employment Agreements
None of the NEOs have employment agreements, other than the change of control severance agreements described above. As
a result, in the event of a termination, retirement, death or disability that is not related to a change of control, an NEO will
only receive the compensation or benefits to which he or she would be entitled under the terms of the defined contribution,
defined benefit, medical or long-term incentive plans, as applicable.
IMPACT OF ACCOUNTING AND TAX TREATMENTS
Accounting Treatment
Services Agreement
As described in Item 13 below, on March 1, 2016, NuStar GP, LLC transferred and assigned to NuStar Services Co, a wholly
owned subsidiary of ours, employment of all of NuStar GP, LLC’s employees. Our executive officers continue to serve as
officers of NuStar GP Holdings and NuStar GP, LLC, and also serve as officers of NuStar Services Co and other NuStar
Energy subsidiaries. Our NEOs serve as employees of both NuStar GP, LLC and NuStar Services Co. In connection with the
transfer and assignment, we amended and restated the Services Agreement such that, beginning March 1, 2016, NuStar GP
Holdings and NuStar Energy receive all management and administrative services from NuStar Services Co. NuStar Energy
reimburses NuStar Services Co for all services provided to NuStar Energy, including payroll and benefit costs, as well as
NuStar Energy unit-based compensation costs. NuStar GP Holdings pays NuStar Services Co an administrative services fee,
subject to certain adjustments, but no longer pays 1.0% of our domestic bonus and unit compensation expenses. Instead,
NuStar GP Holdings retains the expense associated with any NuStar GP Holdings common unit awards or other
compensation that it provides to its officers.
Unit-Based Compensation
By approving the Fifth Amended and Restated 2000 LTIP on January 28, 2016 to permit new issuances of NuStar Energy
common units and then transferring the employees of NuStar GP, LLC into the NuStar Energy consolidated affiliate group on
March 1, 2016, substantially all of our currently outstanding and subsequently issued awards are classified as equity awards,
which reduces the volatility in the expense related to our awards. In addition, we believe that these changes put our structure,
approach to long-term incentives and accounting more in-line with those of our peer MLPs. Prior to the March 1, 2016
employee transfer, we reimbursed NuStar GP, LLC for awards under the 2000 LTIP.
On March 1, 2016, we assumed all outstanding awards under the 2000 LTIP. Our financial statements include the expense
for awards of NuStar Energy restricted units and performance units. The transfer of the outstanding awards qualified as a plan
modification. Therefore, we measured the fair value of then-outstanding awards to domestic employees (including our NEOs)
based on the common unit price on the transfer date. Restricted units awarded to international employees are liability-
classified awards that are cash-settled and measured at fair value based on the common unit price at each reporting period.
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NuStar Energy Restricted Units. Our restricted unit awards are considered phantom units as they represent the right to receive
our common units upon vesting. We account for restricted units expected to result in the issuance of our common units upon
vesting as equity-classified awards. The restricted units granted to our domestic employees (including our NEOs) generally
vest over five years and the restricted units granted to non-employee directors generally vest over three years. We record
compensation expense ratably over the vesting period based on the fair value of the units at the grant date (for domestic
employees, including our NEOs) or the fair value of the units measured at each reporting period (for non-employee directors)
using the market price of our common units on the applicable date. Common unit distribution equivalents paid with respect to
outstanding, unvested equity-classified restricted units reduce equity, similar to cash distributions to unitholders.
NuStar Energy Performance Units. Performance units are equity-classified awards that vest in three increments (tranches)
and represent the right to receive our common units, based upon our achievement of the performance measure set by the
Compensation Committee during the one-year performance periods that end on December 31 of each year following the
grant date. Under applicable accounting standards, a tranche of performance units is not considered “granted” until the
Compensation Committee has set the performance measure for that specific tranche of the award. Therefore, performance
units are measured at the grant date fair value once the performance measure is established for a specific tranche. In addition,
since the performance units granted do not receive common unit distribution equivalents, the estimated fair value of these
awards does not include the per unit distributions expected to be paid to unitholders during the vesting period. We record
compensation expense ratably for each vesting tranche over its one-year service period if it is probable that the specified
performance measure will be achieved. Additionally, changes in the actual or estimated outcomes that affect the quantity of
performance units expected to be converted are recognized as a cumulative adjustment.
NuStar GP Holdings, LLC Restricted Units. NuStar GP Holdings restricted units are phantom units as they represent the right
to receive NuStar GP Holdings’ common units upon vesting. As described above, pursuant to the amended and restated
services agreement, NuStar GP Holdings retains the expense associated with NuStar GP Holdings restricted unit awards.
NuStar GP Holdings accounts for awards of restricted units that it awards under its long-term incentive plan to its directors
and employees (including our NEOs), at fair value. NuStar GP Holdings uses the market price at the grant date as the fair
value of its restricted units. Awards of NuStar GP Holdings’ restricted units to its employees vest over five years, and NuStar
GP Holdings recognizes the resulting compensation expense ratably over the vesting period.
Tax Treatment
Under Section 162(m) of the Code, publicly held corporations may not take a tax deduction for compensation in excess of $1
million paid to the CEO or the other four most highly compensated executive officers unless that compensation meets the
Code’s definition of “performance-based” compensation. Section 162(m) allows a deduction for compensation to a specified
executive that exceeds $1 million only if it is paid (1) solely upon attainment of one or more performance goals, (2) pursuant
to a qualifying performance-based compensation plan adopted by the Compensation Committee and (3) the material terms,
including the performance goals, of such plan are approved by the unitholders before payment of the compensation.
The Compensation Committee considers deductibility under Section 162(m) with respect to compensation arrangements for
executive officers. Although Section 162(m) does not now apply to MLPs, if a similar limitation were to be applied to NuStar
Energy, the Compensation Committee believes that it would be in the company’s best interest for the Compensation
Committee to retain its flexibility and discretion to make compensation awards to foster achievement of performance goals
established by the Compensation Committee (which may include performance goals defined in the Code) and other corporate
goals the Compensation Committee deems important to NuStar Energy’s success, such as encouraging employee retention,
rewarding achievement of non-quantifiable goals and achieving progress with specific projects. The Compensation
Committee believes that the performance unit awards would qualify as performance-based compensation and, therefore,
would not be subject to any deductibility limitations under an applicable section similar to Section 162(m). Grants of
restricted units and other equity-based awards that are not subject to specific quantitative performance measures likely would
not qualify as “performance-based” compensation and, in such event, would be subject to such deduction restrictions.
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COMPENSATION-RELATED POLICIES
Unit Ownership Guidelines
We believe that ownership of NuStar Energy units aligns the interests of NuStar GP, LLC directors and executives with those
of NuStar Energy’s unitholders. We have long emphasized and reinforced the importance of unit ownership among our
executives and directors.
During 2006, the Compensation Committee worked with its independent compensation consultant to formalize unit
ownership and retention guidelines for NuStar GP, LLC directors and officers to ensure continuation of our successful track
record in aligning the interests of NuStar GP, LLC directors and officers with those of NuStar Energy’s unitholders through
ownership of NuStar Energy units. The guidelines initially were approved by the Compensation Committee in January 2006.
In view of the public offerings of units of NuStar GP Holdings in 2006, the guidelines subsequently were amended to include
ownership of either NuStar GP Holdings units or NuStar Energy units.
During 2015, at the request of the Board and its committees, management undertook a review of the unit ownership and
retention guidelines. Management discussed the results of its review with BDO, which agreed with management’s
conclusions. The Compensation Committee and the Nominating/Governance and Conflicts Committee of NuStar GP, LLC’s
Board, as well as the board of directors of NuStar GP Holdings, have approved the updated unit ownership and retention
guidelines described below.
Non-Employee Director Unit Ownership Guidelines
Non-employee directors are expected to acquire and hold during their service as a Board member NuStar Energy units and/or
NuStar GP Holdings units with an aggregate value of at least two times their annual cash retainer. Directors have five years
from their initial election to the Board to meet the target unit ownership guidelines, and they are expected to continuously
own sufficient units to meet the guidelines, once attained. As of December 31, 2016, each of our directors exceeded the
ownership levels set forth in the unit ownership guidelines.
Officer Unit Ownership Guidelines
Unit ownership guidelines for the officers set forth below are as follows:
Officer
CEO/President
EVP serving on CEO’s officer committee
SVP serving on CEO’s officer committee
VP serving on CEO’s officer committee
Value of NuStar Energy Units and/or
NuStar GP Holdings Units Owned
4.0x base salary
3.0x base salary
2.0x base salary
1.0x base salary
The officers subject to the unit ownership and retention guidelines, including each of our NEOs, are expected to meet the
applicable guidelines within five years of becoming subject to the guidelines and continuously own sufficient units to meet
the guidelines, once attained. As of December 31, 2016, each of our NEOs exceeded the ownership levels set forth in the unit
ownership guidelines.
Unit Ownership
For purposes of satisfying the unit ownership guidelines, the following units are considered owned:
•
•
•
units owned directly;
units owned indirectly through possession of the right to sell, transfer and/or vote such units; and
unvested restricted or phantom units granted under our long-term incentive plan or NuStar GP Holdings’ long-term
incentive plan.
Unexercised unit options and unvested performance units are not considered owned for purposes of satisfying the unit
ownership guidelines.
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Prohibition on Insider Trading and Speculation in NuStar Energy or NuStar GP Holdings Units
We have established policies prohibiting our officers, directors and employees from purchasing or selling either NuStar
Energy or NuStar GP Holdings securities while in possession of material, nonpublic information or otherwise using such
information for their personal benefit or in any manner that would violate applicable laws and regulations. Our directors,
officers and certain other employees are prohibited from trading in either NuStar Energy or NuStar GP Holdings securities
for the period beginning on the last business day of each calendar quarter through the first business day following our
disclosure of our quarterly or annual financial results. In addition, our policies prohibit our officers, directors and employees
from speculating in either NuStar Energy or NuStar GP Holdings units, such as by short selling (profiting if the market price
of our units decreases), buying or selling publicly traded options (including writing covered calls), hedging or any other type
of derivative arrangement that has a similar economic effect. Our directors, officers and certain other employees also are
required to obtain consent from the CEO (or, in the case of the CEO, from the Chair of the applicable company’s Audit
Committee) before they enter into margin loans or other financing arrangements that may lead to the ownership or other
rights to their NuStar Energy or NuStar GP Holdings securities being transferred to a third party.
EVALUATION OF COMPENSATION RISK
The Compensation Committee has focused on aligning our compensation policies with the long-term interests of NuStar
Energy and avoiding short-term rewards for management decisions that could pose long-term risks to NuStar Energy. As
described above in “Compensation Discussion and Analysis,” the primary elements of our compensation program are base
salary, annual incentive bonus and long-term incentives. We believe that our compensation program appropriately balances
cash with equity-based compensation and fixed compensation with short- and long-term incentives such that no single pay
element would motivate unnecessary risk taking.
NuStar Energy’s compensation program is structured so that base salaries provide a fixed level of competitive pay that
reflects the individual’s primary duties and responsibilities, and a considerable amount of our management’s compensation is
tied to NuStar Energy’s long-term fiscal health. All bonuses, including executive bonuses, are determined with reference to a
well-defined performance measure selected by the Compensation Committee and applicable to all employees. Historically,
our long-term incentives have taken the form of performance units and restricted units that typically vest over three- and five-
year periods, respectively, which we believe serves to align our employees’ interests with the long-term goals of NuStar
Energy. No business group or unit is compensated differently than any other, regardless of profitability. There also is a
maximum number of performance units that may be earned, based on the performance of NuStar Energy relative to a
performance measure selected by the Compensation Committee. As such, we believe that our compensation policies
encourage employees to operate our business in a fundamentally sound manner, align our executives’ interests with those of
our unitholders and do not create incentives to take risks that are reasonably likely to have a material adverse effect on
NuStar Energy.
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COMPENSATION OF EXECUTIVE OFFICERS AND DIRECTORS
The following pages of this Item 11 provide information required by the SEC regarding compensation paid to or earned by
our NEOs and the members of our Board for the periods indicated. We have used captions and headings in the tables
provided below in accordance with the SEC regulations requiring these disclosures. The footnotes to these tables provide
important information to explain the values presented in the tables, and are an important part of our disclosures.
SUMMARY COMPENSATION TABLE
The following table provides a summary of compensation paid for the years ended December 31, 2016, December 31, 2015
and December 31, 2014 to NuStar GP, LLC’s CEO, CFO and to its three other most highly compensated executive officers
serving during 2016. For each NEO, the table shows amounts earned for services rendered to us in all capacities in which the
NEO served during the periods presented for that NEO.
Name and Principal
Position
Bradley C. Barron
President and CEO
Thomas R. Shoaf
Executive Vice President and
Chief Financial Officer
Mary Rose Brown
Executive Vice President and
Chief Administrative Officer
Amy L. Perry
Senior Vice President, General
Counsel-Corporate and
Commercial Law & Corporate
Secretary
Karen M. Thompson
Senior Vice President and
General Counsel-Litigation,
Regulatory & Environmental
Year
2016
Salary
($)
557,500
Unit
Awards
($)(1)
1,039,456
2015
515,000
1,077,860
2014
2016
460,000
1,086,708
344,600
479,970
2015
334,550
515,023
2014
324,800
564,231
2016
371,200
516,952
2015
360,350
554,552
2014
349,785
607,456
2016
2015
2014
271,800
263,900
250,000
251,130
270,770
294,772
2016
271,800
251,130
2015
263,900
270,770
2014
250,000
302,421
Non-Equity
Incentive
Plan
Compensation
($)(2)
700,000
800,000
683,100
260,000
311,000
321,552
280,000
335,000
346,287
190,000
225,000
226,875
190,000
225,000
226,875
Change in Pension
Value
and Nonqualified
Deferred
Compensation
Earnings
($)(3)
All Other
Compensation
($)(4)
Total
($)
184,931
47,061
147,448
124,479
47,692
142,990
142,437
173,968
136,213
53,496
18,483
51,525
63,605
16,350
68,726
35,698
2,517,585
35,677
2,475,598
29,815
22,924
2,407,071
1,231,973
21,729
1,229,994
21,703
1,375,276
24,520
1,335,109
23,836
1,447,706
23,202
1,462,943
20,882
17,074
8,865
20,329
19,525
16,466
787,308
795,227
832,037
796,864
795,545
864,488
(1) The amounts reported represent the grant date fair value of grants of NuStar Energy restricted units, NuStar Energy
performance units and NuStar GP Holdings restricted units. Under a services agreement in effect prior to March 1,
2016, we reimbursed NuStar GP, LLC for 99% of the compensation expense associated with NuStar Energy awards.
On March 1, 2016, NuStar GP, LLC transferred and assigned to NuStar Services Co, a wholly owned subsidiary of
ours, employment of all of NuStar GP, LLC’s employees and we assumed all outstanding NuStar Energy awards.
Our NEOs are employees of both NuStar Services Co and NuStar GP, LLC. NuStar GP Holdings retains the expense
associated with the NuStar GP Holdings restricted unit awards.
Restricted Units
The grant date fair value for restricted units presented in the table above was determined by multiplying the number
of NuStar Energy restricted units or NuStar GP Holdings restricted units that were granted by the NYSE closing unit
price of NuStar Energy common units or NuStar GP Holdings common units, as applicable, on the date of grant.
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Performance Units
For the 2014 and 2015 rows in the Summary Compensation Table, the grant date fair value of the NuStar Energy
performance units was determined by multiplying the target number of performance units that were granted by the
NYSE closing unit price of NuStar Energy common units on the date of grant.
On March 1, 2016, in connection with the employee transfer, we assumed all outstanding NuStar Energy awards,
and performance unit awards are now equity-classified awards. The transfer qualified as a plan modification, and we
measured the fair value of then-outstanding awards based on our common unit price on the transfer date. Under
applicable accounting standards, a tranche of performance units is not considered “granted” until the Compensation
Committee has set the performance measure for that specific tranche of the award. Therefore, performance units are
measured at the grant date fair value once the performance measure is established for a specific tranche (or, for
2016, the transfer date).
Beginning with the 2016 period, the grant date fair value presented in the Summary Compensation Table includes
the fair value of each tranche of performance units for which the Compensation Committee established a
performance measure during that year. For example, the amount reported for 2016 includes the one tranche of each
of the 2014, 2015 and 2016 performance unit awards that is subject to vesting based on the performance criteria
established by the Compensation Committee on February 24, 2016 with respect to 2016 performance, as illustrated
in the table below:
Award
2014 Performance Unit Award
2015 Performance Unit Award
2016 Performance Unit Award
Tranche Considered “Granted” in 2016
With Respect to 2016 Performance Measure
3rd
2nd
1st
For 2016, the grant date fair value of the NuStar Energy performance units was determined by multiplying the
probable number of performance units for all tranches eligible to vest with respect to 2016 performance (as
illustrated in the table above) by the NYSE closing unit price of NuStar Energy common units on the transfer date,
reduced by the per unit value of distributions not paid on performance units prior to vesting.
If the maximum number of NuStar Energy performance units had been used to determine the grant date fair value of
performance units for the 2016 period presented, the grant date fair value for performance units for Mr. Barron, Mr.
Shoaf, Ms. Brown, Ms. Perry and Ms. Thompson would have been: $618,392, $305,958, $329,514, $158,534 and
$158,534, respectively.
Please see the “Long-Term Incentive Awards” section and the “Accounting Treatment” section of “Compensation
Discussion and Analysis” above in this Item 11 for additional information regarding the vesting schedules and the
assumptions made in the valuation.
(2) The amounts reported as “non-equity incentive plan compensation” reflect the annual incentive bonus amounts paid
to our NEOs pursuant to the annual bonus plan. Bonus amounts are paid in February of each year with respect to
performance during the immediately preceding year. Bonuses are determined taking into consideration NuStar
Energy’s performance in the applicable year, the individual NEO’s targets and the NEO’s performance, as described
above under “Compensation Discussion and Analysis-Elements of Executive Compensation-Annual Incentive
Bonus.” For an explanation of the amount of salary and bonus in proportion to total compensation, see
“Compensation Discussion and Analysis-Elements of Executive Compensation-Relative Size of Primary Elements
of Compensation.”
(3) The amounts reported reflect the amounts attributable to the aggregate change in the actuarial present value of each
NEOs accumulated benefit under our defined benefit and actuarial pension plans, including supplemental plans (but
excluding tax-qualified defined contribution plans and nonqualified defined contribution plans). None of the NEOs
received any above-market or preferential earnings on compensation that is deferred on a basis that is not tax-
qualified during the periods presented.
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(4) The amounts reported in this column for 2016 consist of the following for each NEO:
Company
Contribution
to Thrift
Plan ($)
15,900
15,900
14,970
15,900
15,755
Company
Contribution
to Excess
Thrift Plan ($)
17,550
4,776
7,302
408
—
Tax
Preparation
($)
Personal
Liability
Insurance
($)
850
850
850
850
850
1,398
1,398
1,398
1,398
1,398
Name
Barron
Shoaf
Brown
Perry
Thompson
Executive
Health
—
Exams ($)(a) TOTAL ($)
35,698
22,924
24,520
20,882
20,329
—
2,326
2,326
—
(a) The amount reported is the difference between the value of the respective NEO’s health exams and the value of
NuStar Energy’s all-employee wellness assessments.
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GRANTS OF PLAN-BASED AWARDS
DURING THE YEAR ENDED DECEMBER 31, 2016
The following table provides information regarding grants of plan-based awards to the NEOs during 2016.
Date of
Approval by
Compensation
Committee of
Equity-Based
Awards
Estimated Future Payouts
Under Non-Equity
Incentive Plan Awards
Estimated Future Payouts
Under Equity
Incentive Plan Awards
Threshold
($)
Target
($)
Maximum
($)
Threshold
(#)
Target
(#)
Maximum
(#)
N/A
501,750
557,500
1,115,000
—
—
—
2/24/2016
10/26/2016
10/26/2016
—
—
—
—
—
—
—
—
—
N/A
186,084
206,760
413,520
2/24/2016
10/26/2016
10/26/2016
—
—
—
—
—
—
—
—
—
N/A
200,448
222,720
445,440
2/24/2016
10/26/2016
10/26/2016
—
—
—
—
—
—
—
—
—
N/A
134,541
149,490
298,980
2/24/2016
10/26/2016
10/26/2016
—
—
—
—
—
—
—
—
—
N/A
134,541
149,490
298,980
8,766
9,740
19,480
—
—
—
—
—
—
—
—
—
4,337
4,819
9,638
—
—
—
—
—
—
—
—
—
4,671
5,190
10,380
—
—
—
—
—
—
—
—
—
2,247
2,497
4,994
—
—
—
—
—
—
—
—
—
2/24/2016
10/26/2016
10/26/2016
—
—
—
—
—
—
—
—
—
2,247
2,497
4,994
—
—
—
—
—
—
All Other
Unit
Awards:
Number
of
Units (#)
—
—
11,000
9,000
—
—
4,920
4,040
—
—
5,300
4,350
—
—
2,585
2,125
—
—
2,585
2,125
Grant Date
Fair Value of
Unit
Awards ($)
—
309,196
503,910
226,350
—
152,979
225,385
101,606
—
164,757
242,793
109,403
—
79,267
118,419
53,444
—
79,267
118,419
53,444
Name
Grant Date
Barron
Shoaf
Brown
Perry
Thompson
N/A
3/1/2016
11/16/2016
11/16/2016
N/A
3/1/2016
11/16/2016
11/16/2016
N/A
3/1/2016
11/16/2016
11/16/2016
N/A
3/1/2016
11/16/2016
11/16/2016
N/A
3/1/2016
11/16/2016
11/16/2016
(1)
(2)
(3)
(4)
(1)
(2)
(3)
(4)
(1)
(2)
(3)
(4)
(1)
(2)
(3)
(4)
(1)
(2)
(3)
(4)
(1) The amounts reported represent the threshold, target and maximum amounts that would potentially be payable to the
NEOs as annual incentive bonus awards under the annual bonus plan with respect to 2016 performance. The actual
amounts paid with respect to 2016 performance are reported in the “Non-Equity Incentive Plan Compensation”
column of the Summary Compensation Table. Bonuses are determined taking into consideration NuStar Energy’s
performance in the applicable year, the individual NEO’s targets and the NEO’s performance, as described above
under “Compensation Discussion and Analysis-Elements of Executive Compensation-Annual Incentive Bonus.”
(2) Performance units were awarded by the Compensation Committee on February 24, 2016 pursuant to the 2000 LTIP.
On March 1, 2016, in connection with the employee transfer, we assumed all outstanding NuStar Energy awards,
and performance unit awards are now equity-classified awards. The transfer qualified as a plan modification and we
measured the fair value of outstanding awards based on our common unit price on the transfer date. Performance
units vest in three annual increments (tranches), based upon our achievement of the performance measure set by the
Compensation Committee during the one-year performance periods that end on December 31 of each year following
the date of grant. Under applicable accounting standards, a tranche of performance units is not considered “granted”
until the Compensation Committee has set the performance measure for that specific tranche of the award.
Therefore, performance units are measured at the grant date fair value once the performance measure is established
for a specific tranche (or, for 2016, the transfer date). In addition, since the performance units granted do not receive
common unit distribution equivalents, the estimated fair value of these awards does not include the per unit
distributions expected to be paid to unitholders during the vesting period.
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The estimated future payouts and the grant date fair value presented in the table above with respect to performance
units includes each tranche of performance units for which the Compensation Committee established a performance
measure during 2016. For 2016, the amounts presented include the one tranche of each of the 2014, 2015 and 2016
performance unit awards that is subject to vesting based on the performance criteria established by the
Compensation Committee on February 24, 2016 with respect to 2016 performance, as illustrated in the table below:
Award
2014 Performance Unit Award
2015 Performance Unit Award
2016 Performance Unit Award
Tranche Considered “Granted” in 2016
With Respect to 2016 Performance Measure
3rd
2nd
1st
For the performance period ended December 31, 2016, the performance units available to vest under the applicable
tranche for each of the 2014 awards, 2015 awards and 2016 awards vested at 150% based on the performance level
attained. See “Compensation Discussion and Analysis-Elements of Executive Compensation-Long Term Incentive
Awards-Performance Units” for a description of the performance measure and the performance level attained with
respect to the 2016 performance period. See “Compensation Discussion and Analysis-Impact of Accounting and Tax
Treatments-Accounting Treatment” and footnote (1) to the Summary Compensation Table above in this Item 11 for
information regarding the assumptions made in valuation.
(3) Restricted units of NuStar Energy were approved by the Compensation Committee at a joint meeting with the
compensation committee of NuStar GP Holdings on October 26, 2016, and the grant date for these NuStar Energy
restricted units was set at that time for the date that was as soon as administratively practicable after the meeting and
no earlier than the third business day following our third quarter earnings release. The NuStar Energy restricted units
were awarded pursuant to the 2000 LTIP and vest 1/5 annually over five years beginning on the first anniversary of
the grant date. All grantees receiving NuStar Energy restricted units are entitled to receive an amount in cash equal
to the product of (a) the number of restricted units granted to the grantee that remain outstanding and unvested as of
the record date for such quarter and (b) the quarterly distribution declared by the Board for such quarter with respect
to NuStar Energy’s common units. See “Compensation Discussion and Analysis-Impact of Accounting and Tax
Treatments-Accounting Treatment” and footnote (1) to the Summary Compensation Table above in this Item 11 for
information regarding the assumptions made in valuation.
(4) Restricted units of NuStar GP Holdings were approved by the compensation committee of NuStar GP Holdings at a
joint meeting with the Compensation Committee of NuStar GP, LLC on October 26, 2016, and the grant date for
these NuStar GP Holdings restricted units was set at that time for the date that was as soon as administratively
practicable after the meeting and no earlier than the third business day following NuStar GP Holdings’ third quarter
earnings release. The NuStar GP Holdings restricted units were awarded pursuant to the NuStar GP Holdings Long-
Term Incentive Plan, as amended and restated as of April 1, 2007, and vest 1/5 annually over five years beginning
on the first anniversary of the grant date. All grantees receiving NuStar GP Holdings restricted units are entitled to
receive an amount in cash equal to the product of (a) the number of restricted units granted to the grantee that
remain outstanding and unvested as of the record date for such quarter and (b) the quarterly distribution declared by
the NuStar GP Holdings Board for such quarter with respect to NuStar GP Holdings’ common units. See
“Compensation Discussion and Analysis-Impact of Accounting and Tax Treatments-Accounting Treatment” and
footnote (1) to the Summary Compensation Table above in this Item 11 for information regarding the assumptions
made in valuation.
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OUTSTANDING EQUITY AWARDS
AT DECEMBER 31, 2016
The following table provides information regarding our NEOs’ unvested restricted units and the target amount of our NEOs’
unvested performance units as of December 31, 2016. The value of NuStar Energy restricted units or performance units
reported below is equal to the number of restricted units or performance units reflected in the table, as applicable, multiplied
by $49.80, the NuStar Energy common unit closing price on the NYSE on December 30, 2016 (the last trading day of 2016).
The value of the NuStar GP Holdings restricted units reported below is equal to the number of restricted units reflected in the
table multiplied by $28.90, the NuStar GP Holdings common unit closing price on the NYSE on December 30, 2016 (the last
trading day of 2016). The footnotes to the table describe the vesting schedules for the unvested restricted units and the
unvested performance units reflected in the table. None of our NEOs had outstanding unit options as of December 31, 2016.
Unit Awards
Number of Units
That Have Not
Vested (#)
Market
Value of
Units That
Have Not
Vested ($)
Equity
Incentive
Plan Awards:
Number of
Unearned Units
or Other Rights
That Have Not
Vested (#)
Equity
Incentive
Plan Awards:
Market or
Payout Value of
Unearned Units
or Other Rights
That Have Not
Vested ($)
—
—
21,220
1,056,756
25.883
1,288,973
19,577
565,775
—
—
—
—
—
—
10,288
512,342
12,548
624,890
274,117
9,485
—
—
—
—
—
—
11,080
551,784
14,281
711,194
10,764
311,080
—
—
—
—
—
6,913
4,334
—
6,873
4,334
—
5,373
267,575
344,267
125,253
—
—
—
—
—
5,373
267,575
342,275
125,253
—
—
—
—
Name
Barron
Shoaf
Brown
Perry
Type of Award
NuStar Energy
Performance Unit (1)
NuStar Energy
Restricted Unit (2)
NuStar GP Holdings
Restricted Unit (3)
NuStar Energy
Performance Unit(4)
NuStar Energy
Restricted Unit (5)
NuStar GP Holdings
Restricted Unit (6)
NuStar Energy
Performance Unit (7)
NuStar Energy
Restricted Unit (8)
NuStar GP Holdings
Restricted Unit (9)
NuStar Energy
Performance Unit (10)
NuStar Energy
Restricted Unit (11)
NuStar GP Holdings
Restricted Unit (12)
Thompson NuStar Energy
Performance Unit (13)
NuStar Energy
Restricted Unit (14)
NuStar GP Holdings
Restricted Unit (15)
(1) Mr. Barron’s target number of NuStar Energy performance units consist of: 2,666 units awarded July 23, 2014;
5,333 units awarded January 29, 2015; and 13,221 units awarded February 24, 2016.
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The performance units awarded in 2014, 2015 and 2016 are eligible to vest in three annual increments and are
payable in NuStar Energy’s common units. Upon vesting, the performance units are converted into a number of
NuStar Energy common units based upon NuStar Energy’s performance during the one-year performance periods
that end on December 31 of each year following the date of grant against an objective performance measure
established by the Compensation Committee.
On January 26, 2017, the Compensation Committee determined that, for the performance period ended
December 31, 2016, the performance units available to vest under the 2014 awards, 2015 awards and 2016 awards
with respect to 2016 performance vested at 150% on January 26, 2017 based on the performance level attained. If all
unvested performance units reported in the table vested at 200% (the maximum level), the number of performance
units outstanding and the market value thereof as of December 31, 2016 would be twice the amounts reflected in the
table. See “Compensation Discussion and Analysis-Elements of Executive Compensation-Long Term Incentive
Awards-Performance Units” for a description of the performance measure and the performance level attained with
respect to the 2016 performance period.
(2) Mr. Barron’s restricted NuStar Energy units consist of: 690 restricted units granted December 19, 2012; 1,900
restricted units granted December 16, 2013; 4,293 restricted units granted December 19, 2014; 8,000 restricted units
granted November 16, 2015; and 11,000 restricted units granted November 16, 2016. All of Mr. Barron’s NuStar
Energy restricted units vest in 1/5 increments over five years, beginning on the first anniversary of the date of grant.
(3) Mr. Barron’s restricted NuStar GP Holdings units consist of: 478 restricted units granted December 19, 2012; 1,376
restricted units granted December 16, 2013; 2,883 restricted units granted December 19, 2014; 5,840 restricted units
granted November 16, 2015; and 9,000 restricted units granted November 16, 2016. All of Mr. Barron’s NuStar GP
Holdings restricted units vest in 1/5 increments over five years, beginning on the first anniversary of the date of
grant.
(4) Mr. Shoaf’s target number of NuStar Energy performance units consist of: 1,428 units awarded July 23, 2014; 2,626
units awarded January 29, 2015; and 6,234 units awarded February 24, 2016. The performance units vest in
accordance with the description in footnote (1) above.
(5) Mr. Shoaf’s restricted NuStar Energy units consist of: 468 restricted units granted December 19, 2012; 1,274
restricted units granted December 16, 2013; 2,166 restricted units granted December 19, 2014; 3,720 restricted units
granted November 16, 2015; and 4,920 restricted units granted November 16, 2016. All of Mr. Shoaf’s NuStar
Energy restricted units vest in 1/5 increments over five years, beginning on the first anniversary of the date of grant.
(6) Mr. Shoaf’s restricted NuStar GP Holdings units consist of: 324 restricted units granted December 19, 2012; 922
restricted units granted December 16, 2013; 1,455 restricted units granted December 19, 2014; 2,744 restricted units
granted November 16, 2015 and 4,040 restricted units granted November 16, 2016. All of Mr. Shoaf’s NuStar GP
Holdings restricted units vest in 1/5 increments over five years, beginning on the first anniversary of the date of
grant.
(7) Ms. Brown’s target number of NuStar Energy performance units consist of: 1,538 units awarded July 23, 2014;
2,828 units awarded January 29, 2015; and 6,714 units awarded February 24, 2016. The performance units vest in
accordance with the description in footnote (1) above.
(8) Ms. Brown’s restricted NuStar Energy units consist of: 746 restricted units granted December 19, 2012; 1,900
restricted units granted December 16, 2013; 2,331 restricted units granted December 19, 2014; 4,004 restricted units
granted November 16, 2015; and 5,300 restricted units granted November 16, 2016. All of Ms. Brown’s NuStar
Energy restricted units vest in 1/5 increments over five years, beginning on the first anniversary of the date of grant.
(9) Ms. Brown’s restricted NuStar GP Holdings units consist of: 516 restricted units granted December 19, 2012; 1,376
restricted units granted December 16, 2013; 1,566 restricted units granted December 19, 2014; 2,956 restricted units
granted November 16, 2015; and 4,350 restricted units granted November 16, 2016. All of Ms. Brown’s NuStar GP
Holdings restricted units vest in 1/5 increments over five years, beginning on the first anniversary of the date of
grant.
(10) Ms. Perry’s target number of NuStar Energy performance units consist of: 714 units awarded July 23, 2014; 1,380
units awarded January 29, 2015; and 3,279 units awarded February 24, 2016. The performance units vest in
accordance with the description in footnote (1) above.
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(11) Ms. Perry’s restricted NuStar Energy units consist of: 372 restricted units granted December 19, 2012; 860 restricted
units granted December 16, 2013; 1,140 restricted units granted December 19, 2014; 1,956 restricted units granted
November 16, 2015; and 2,585 restricted units granted November 16, 2016. All of Ms. Perry’s NuStar Energy
restricted units vest in 1/5 increments over five years, beginning on the first anniversary of the date of grant.
(12) Ms. Perry’s restricted NuStar GP Holdings units consist of: 765 restricted units granted December 19, 2014; 1,444
restricted units granted November 16, 2015; and 2,125 restricted units granted November 16, 2016. All of
Ms. Perry’s NuStar GP Holdings restricted units vest in 1/5 increments over five years, beginning on the first
anniversary of the date of grant.
(13) Ms. Thompson’s target number of NuStar Energy performance units consist of: 714 units awarded July 23, 2014;
1,380 units awarded January 29, 2015; and 3,279 units awarded February 24, 2016. The performance units vest in
accordance with the description in footnote (1) above.
(14) Ms. Thompson’s restricted NuStar Energy units consist of: 332 restricted units granted December 19, 2012; 860
restricted units granted December 16, 2013; 1,140 restricted units granted December 19, 2014; 1,956 restricted units
granted November 16, 2015; and 2,585 restricted units granted November 16, 2016. All of Ms. Thompson’s NuStar
Energy restricted units vest in 1/5 increments over five years, beginning on the first anniversary of the date of grant.
(15) Ms. Thompson’s restricted NuStar GP Holdings units consist of: 765 restricted units granted December 19, 2014;
1,444 restricted units granted November 16, 2015; and 2,125 restricted units granted November 16, 2016. All of
Ms. Thompson’s NuStar GP Holdings restricted units vest in 1/5 increments over five years, beginning on the first
anniversary of the date of grant.
OPTION EXERCISES AND UNITS VESTED
DURING THE YEAR ENDED DECEMBER 31, 2016
The following table provides information regarding the vesting of restricted units and performance units held by our NEOs
during 2016. None of our NEOs had outstanding unit option awards during 2016.
Name
Barron
Shoaf
Brown
Perry
Thompson
Unit Awards
Number of Units
Acquired on Vesting (#)
Value Realized
on Vesting ($)(1)
22,890(2)
12,482(3)
15,693(4)
5,380(5)
5,340(6)
775,924
422,986
536,597
194,385
192,468
(1) The value realized on vesting of NuStar Energy restricted units and performance units was calculated by multiplying
the closing price of NuStar Energy common units on the NYSE on the date of vesting by the number of NuStar
Energy units vested. The value realized on vesting of NuStar GP Holdings restricted units was calculated by
multiplying the closing price of NuStar GP Holdings common units on the NYSE on the date of vesting by the
number of NuStar GP Holdings units vested. The closing prices on the applicable dates are as follows:
Closing Prices for 2016 Vestings
Date
January 28, 2016
November 16, 2016
December 16, 2016
December 19, 2016
Date
November 16, 2016
December 16, 2016
December 19, 2016
NuStar Energy Closing Price ($)
30.54
45.81
47.95
47.93
NuStar GP Holdings Closing Price ($)
25.15
26.50
26.75
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(2) Mr. Barron's restricted NuStar Energy units vested in 2016 as follows: 2,000 units on November 16, 2016; 1,578
units on December 16, 2016; and 2,121 units on December 19, 2016. Mr. Barron's restricted NuStar GP Holdings
units vested in 2016 as follows: 1,460 units on November 16, 2016; 1,166 units on December 16, 2016; and 1,439
units on December 19, 2016. On January 28, 2016, 13,126 of Mr. Barron’s NuStar Energy performance units
vested.
(3) Mr. Shoaf’s restricted NuStar Energy units vested in 2016 as follows: 930 units on November 16, 2016; 946 units on
December 16, 2016; and 1,190 units on December 19, 2016. Mr. Shoaf’s restricted NuStar GP Holdings units vested
in 2016 as follows: 686 units on November 16, 2016; 697 units on December 16, 2016; and 809 units on December
19, 2016. On January 28, 2016, 7,224 of Mr. Shoaf’s NuStar Energy performance units vested.
(4) Ms. Brown’s restricted NuStar Energy units vested in 2016 as follows: 1,001 units on November 16, 2016; 1,628
units on December 16, 2016; and 1,523 units on December 19, 2016. Ms. Brown’s restricted NuStar GP Holdings
units vested in 2016 as follows: 739 units on November 16, 2016; 1,204 units on December 16, 2016; and 1,038
units on December 19, 2016. On January 28, 2016, 8,560 of Ms. Brown’s NuStar Energy performance units vested.
(5) Ms. Perry’s restricted NuStar Energy units vested in 2016 as follows: 489 units on November 16, 2016; 715 units on
December 16, 2016; and 752 units on December 19, 2016. Ms. Perry’s restricted NuStar GP Holdings units vested in
2016 as follows: 361 units on November 16, 2016; and 255 units on December 19, 2016. On January 28, 2016,
2,808 of Ms. Perry’s NuStar Energy performance units vested.
(6) Ms. Thompson’s restricted NuStar Energy units vested in 2016 as follows: 489 units on November 16, 2016; 715
units on December 16, 2016; and 712 units on December 19, 2016. Ms. Thompson’s restricted NuStar GP Holdings
units vested in 2016 as follows: 361 units on November 16, 2016; and 255 units on December 19, 2016. On January
28, 2016, 2,808 of Ms. Thompson’s NuStar Energy performance units vested.
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POST-EMPLOYMENT COMPENSATION
PENSION BENEFITS
FOR THE YEAR ENDED DECEMBER 31, 2016
We maintain a noncontributory defined benefit pension plan (the Pension Plan) in which most of our employees are eligible
to participate and under which contributions by individual participants are neither required nor permitted. We also maintain a
noncontributory, non-qualified excess pension plan (the Excess Pension Plan), which provides supplemental pension benefits
to certain highly compensated employees. The Excess Pension Plan provides eligible employees with additional retirement
savings opportunities that cannot be achieved with tax-qualified plans due to the Code’s limits on (1) annual compensation
that can be taken into account under qualified plans or (2) annual benefits that can be provided under qualified plans.
The following table provides information regarding the accumulated benefits of our NEOs under our pension plans during the
year ended December 31, 2016.
Name
Barron
Shoaf
Plan Name
Pension Plan
Excess Pension Plan
Pension Plan
Excess Pension Plan
Brown
Pension Plan
Perry
Excess Pension Plan
Pension Plan
Excess Pension Plan
Thompson
Pension Plan
Excess Pension Plan
Number of Years
Credited Service
Present Value of
Accumulated
Benefit ($)(1)
Payments During Last
Fiscal Year ($)
(2)
(2)
(2)
(2)
(2)
(2)
(2)
(2)
(2)
(2)
291,658
466,272
401,971
392,448
406,018
501,446
172,787
53,871
253,109
57,416
—
—
—
—
—
—
—
—
—
—
(1) The present values stated in the table above were calculated using the same interest rates and mortality tables we use
for our financial reporting. The present values as of December 31, 2016 were determined using plan-specific
discount rates (4.33% for the Pension Plan and 3.70% for the Excess Pension Plan) and the plans’ earliest unreduced
retirement age (age 62). The present values reflect post-retirement mortality rates based on the RP2006 generational
mortality table projected using scale MP2016. No decrements were included for pre-retirement termination,
mortality or disability. Where applicable, lump sums were determined based on a 3.83% interest rate and the
mortality table prescribed by the IRS in Rev. Ruling 2007-67 and updated by IRS Notices 2008-85 and 2013-49 for
distributions in the years 2009-2016.
(2) As of December 31, 2013, the final average pay formula used in the Pension Plan and the Excess Pension Plan,
which was based on years of service and compensation during service, was frozen. Benefits for service after
December 31, 2013 accrue under a cash balance formula described below. The number of years of credited service
under the final average pay formula and the cash balance formula for each of our NEOs under the Pension Plan and
the Excess Pension Plan are set forth below.
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Name
Barron
Shoaf
Brown
Perry
Thompson
Pension Plan
Plan Name
Pension Plan
Excess Pension Plan
Pension Plan
Excess Pension Plan
Pension Plan
Excess Pension Plan
Pension Plan
Excess Pension Plan
Pension Plan
Excess Pension Plan
Number of Years
Credited Service - Final
Average Pay Formula
(Frozen as of
December 31, 2013)
Number of Years
Credited Service - Cash
Balance Formula
7.5
13.0
7.5
28.5
6.7
6.7
7.5
7.5
6.7
11.7
16.0
16.0
31.5
31.5
19.3
19.3
14.0
14.0
14.7
14.7
The Pension Plan is a qualified, non-contributory defined benefit pension plan that became effective as of July 1, 2006. The
Pension Plan covers substantially all of our employees and generally provides retirement income calculated under a cash
balance formula (CBF), which is based on age, years of vesting service and interest credits. Employees become fully vested
in their CBF benefits upon attaining three years of service. Prior to January 1, 2014, eligible employees were covered under
either the CBF or a defined benefit final average pay formula (FAP) based on years of service and compensation during their
period of service, and employees became fully vested in their benefits upon attaining five years of service under the FAP and
upon attaining three years of service under the CBF. The Pension Plan was amended to freeze the FAP benefit at December
31, 2013 and, on or after January 1, 2014, all employees are covered under the CBF.
An eligible employee’s benefits under the Pension Plan will be equal to:
•
•
1.6% of the employee’s average monthly compensation multiplied by the employee’s years of credited service for
service through December 31, 2013 for the FAP benefit plus
the employee’s CBF account balance.
An employee may start receiving his or her benefits under the Pension Plan at any time following his or her separation of
service, but must begin receiving benefits by April 1 of the year after the employee attains age 70½. Mr. Shoaf and Ms.
Brown have attained the Early Retirement Age, which is defined in the Pension Plan as age 55. If an employee with a FAP
benefit begins receiving benefits after the Early Retirement Age and before age 62, the FAP benefit amount will be reduced
by 4% for each full year between the benefit start date and age 62. If an employee with a FAP benefit begins receiving
benefits before the Early Retirement Age, the amount of the FAP benefit will be the actuarial equivalent of the lump sum that
otherwise would have been payable on the date the employee starts benefits. The CBF benefit amount under the Pension
Plan is based on the CBF account balance and, therefore, is not reduced based on the age at which the employee begins
receiving benefits.
Excess Pension Plan
The Excess Pension Plan, which became effective July 1, 2006, provides benefits to our eligible employees whose pension
benefits under the Pension Plan and the Valero Energy Pension Plan, where applicable, are subject to limitations under the
Code. The Excess Pension Plan is an excess benefit plan as contemplated under ERISA for those benefits provided in excess
of the maximum amount allowable under Section 415 of the Code. Benefits provided as a result of other statutory limitations
are limited to a select group of management or highly compensated employees. The Excess Pension Plan is not intended to
constitute either a qualified plan under the Code or a funded plan subject to ERISA. For our employees who were eligible to
receive a benefit under the Valero Energy Excess Pension Plan (the Predecessor Excess Pension Plan) as of July 1, 2006, the
Excess Pension Plan assumed the liabilities of the Predecessor Excess Pension Plan and will provide a single, nonqualified
defined benefit to eligible employees for their pre-July 1, 2006 benefit accruals under the Predecessor Excess Pension Plan
and their post-July 1, 2006 benefit accruals under the Excess Pension Plan.
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An eligible employee’s monthly pension under the Excess Pension Plan will be equal to:
•
•
•
1.6% of the employee’s average monthly compensation multiplied by the employee’s years of credited service for
service through December 31, 2013, plus
the employee’s CBF benefits without regard to the limitations imposed by the Code, less
the employee’s Pension Plan benefit.
All of our NEOs participated in the Excess Pension Plan during 2016.
NONQUALIFIED DEFERRED COMPENSATION
FOR THE YEAR ENDED DECEMBER 31, 2016
The following table provides information regarding our contributions and the contributions by each of our NEOs under our
non-qualified defined contribution plan, the Excess Thrift Plan, during the year ended December 31, 2016. The table also
presents each NEO’s withdrawals, earnings and year-end balances in such plan. Please see the description of our Excess
Thrift Plan above in “Compensation Discussion and Analysis-Elements of Executive Compensation-Post-Employment
Benefits.”
Executive
Contributions
in 2016 ($)(1)
Registrant
Contributions in
2016 ($)(2)
Aggregate
Earnings in
2016 ($)(3)
—
—
—
—
—
17,550
4,776
7,302
408
—
19,367
2,850
17,650
—
—
Name
Barron
Shoaf
Brown
Perry
Thompson
Aggregate
Withdrawals/
Distributions ($)
—
—
—
—
—
Aggregate
Balance at
December 31,
2016 ($)(4)
84,430
14,017
69,744
408
—
(1) The NEOs made no contributions during 2016.
(2) Amounts reported represent our contributions to our Excess Thrift Plan. All of the amounts included in this column
are included within the amounts reported as “All Other Compensation” for 2016 in the Summary Compensation
Table.
(3) Amounts include the earnings and losses, if any, of each NEO’s respective account in our Excess Thrift Plan.
(4) Amounts include the aggregate balance at year end, if any, of each NEO’s respective account in our Excess Thrift
Plan and include registrant contributions that were previously reported as compensation to each of the NEOs in the
“All Other Compensation” column in the Summary Compensation Table for 2016 and previous years.
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POTENTIAL PAYMENTS UPON TERMINATION OR CHANGE OF CONTROL
SEC regulations require us to disclose potential payments to an NEO in connection with his or her termination or a change of
control of NuStar Energy, other than those amounts disclosed under the headings “Pension Benefits For The Year Ended
December 31, 2016” and “Nonqualified Deferred Compensation For The Year Ended December 31, 2016” above in this Item
11 or amounts pursuant to arrangements that do not discriminate in favor of executive officers and are generally available to
salaried employees. The following narrative and table provide the required disclosures.
None of our NEOs have employment agreements, other than the change of control severance agreements described below. As
a result, in the event of a termination, retirement, death or disability that does not occur in connection with a change of
control, an NEO will only receive the compensation or benefits to which he or she would already be entitled under the terms
of, as applicable, the defined contribution, defined benefit, medical or long-term incentive plans. Therefore, these scenarios
are not presented in the table below.
Each of our NEOs has entered into a change of control severance agreement with NuStar Energy and our wholly owned
subsidiary, NuStar Services Co. These agreements seek to ensure the continued availability of these executives in the event of
a “change of control” (described below). The agreements contain tiers of compensation and benefits based on each NEO’s
position, with each tier corresponding to a certain severance multiple used to calculate total compensation and benefits to be
provided under the agreements. We amended and restated the change of control severance agreements on August 1, 2016 to:
•
•
•
•
reflect NuStar Services Co, our wholly owned subsidiary, as the employer;
create a new tier and corresponding severance multiple for Executive Vice Presidents (of which we had none when
the previous agreements were adopted);
align each NEO with the applicable severance multiple to reflect each NEO’s promotions and associated changes in
position since entering into the previous agreements;
add a requirement that the NEO execute a release of claims against NuStar Energy, NuStar Services Co and
affiliated companies (as defined in the agreements) in order to be eligible to retain compensation and benefits
provided under the agreements; and
•
reflect legal developments since the previous agreements.
The following table sets forth the severance multiple applicable to each NEO, based on his or her current officer position.
Name
Applicable Officer Position
Severance Multiple
Barron
Shoaf
Brown
Perry
Thompson
Chief Executive Officer
Executive Vice President
Executive Vice President
Senior Vice President
Senior Vice President
3
2.5
2.5
2
2
If a change of control occurs, the agreements become operative for a fixed three-year period. The agreements provide
generally that the NEO’s terms of employment will not be adversely changed during the three-year period after a change of
control. In addition, outstanding unit options held by the NEO will automatically vest, restrictions applicable to outstanding
restricted units held by the NEO will lapse and all unvested performance units held by the NEO will fully vest and become
payable at 200% of target. Certain of the NEOs also are entitled to receive a payment in an amount sufficient to make the
NEO whole for any excise tax on excess parachute payments imposed under Section 4999 of the Code, as set forth in the
table below. Each agreement subjects the NEO to obligations of confidentiality, both during the term and after termination,
for secret and confidential information that the NEO acquired during his or her employment relating to NuStar Energy,
NuStar Services Co and affiliated companies.
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For purposes of these agreements, a “change of control” means any of the following (subject to additional particulars as
stated in the agreements):
•
•
the acquisition by an individual, entity or group of beneficial ownership of 40% of NuStar GP Holdings’ voting
interests;
the failure of NuStar GP Holdings to control NuStar GP, LLC, NuStar Energy’s general partner, Riverwalk
Logistics, L.P., or all of the general partner interests of NuStar Energy;
• Riverwalk Logistics, L.P. ceases to be NuStar Energy’s general partner or Riverwalk Logistics, L.P. is no longer
•
•
•
•
•
•
controlled by either NuStar GP, LLC or one of its affiliated companies;
the acquisition of more than 50% of all voting interests of NuStar Energy then outstanding;
certain consolidations or mergers of NuStar GP Holdings;
certain consolidations or mergers of NuStar Energy;
the sale of all or substantially all of the assets of NuStar GP Holdings to anyone other than its affiliated
companies;
the sale of all or substantially all of the assets of NuStar Energy to anyone other than its affiliated companies; or
a change in the composition of the NuStar GP Holdings board of directors so that fewer than a majority of those
directors are “incumbent directors” as defined in the agreements.
In the agreements, “cause” is defined to mean, generally, the willful and continued failure of the NEO to perform
substantially his or her duties, or the willful engaging by the NEO in illegal or gross misconduct that is materially and
demonstrably injurious to NuStar Energy, NuStar Services Co or any affiliated company. “Good reason” is defined to mean,
generally:
•
•
•
a diminution in the NEO’s position, authority, duties or responsibilities;
failure of the successor of NuStar Energy or NuStar Services Co to assume and perform under the agreement;
and
relocation of the NEO or increased travel requirements.
Except as otherwise noted, the values in the table below assume that a change of control occurred on December 31, 2016 and
that the NEO’s employment terminated on that date.
Under the change of control severance agreements, if an NEO’s employment is terminated for “cause” following a change of
control, the NEO will not receive any additional benefits or compensation as a result of the termination and will only receive
accrued salary or vacation pay that remained unpaid through the date of termination and any other benefits that the NEO
would already be entitled to receive, if any. Therefore, there is no presentation of termination for “cause” in the table below.
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Executive Benefits and
Payments(1)
Salary (1)
Barron
Shoaf
Brown
Perry
Thompson
Bonus (1)
Barron
Shoaf
Brown
Perry
Thompson
Pension and Excess
Pension Benefits
Barron
Shoaf
Brown
Perry
Thompson
Contributions under
Defined Contribution
Plans
Barron
Shoaf
Brown
Perry
Thompson
Health and Welfare Plan
Benefits (6)
Barron
Shoaf
Brown
Perry
Thompson
Accelerated Vesting of
Unit Options
Barron
Shoaf
Brown
Perry
Thompson
Termination of
Employment by the
Employer Other Than
for “Cause,” Death
or Disability, or by
the Executive for
“Good Reason” ($)(2)
Termination of
Employment
because of Death or
Disability ($)(3)
Termination by the
Executive Other
Than for “Good
Reason” ($)(4)
Continued
Employment
Following Change
of Control ($)(5)
—
—
—
—
—
800,000
321,552
346,287
226,875
226,875
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
800,000
321,552
346,287
226,875
226,875
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
1,725,000
874,250
941,750
551,600
551,600
3,200,000
1,125,432
1,212,005
680,625
680,625
405,017
236,994
266,924
77,730
98,353
100,350
51,690
55,680
32,616
31,510
43,729
53,709
28,662
23,419
42,967
—
—
—
—
—
—
—
—
—
—
800,000
321,552
346,287
226,875
226,875
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
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Executive Benefits and
Payments(1)
Accelerated Vesting of
Restricted Units (7)
Barron
Shoaf
Brown
Perry
Thompson
Accelerated Vesting of
Performance Units (8)
Barron
Shoaf
Brown
Perry
Thompson
280G Tax Gross-Up (9)
Barron
Shoaf
Brown
Perry
Thompson
Totals
Barron
Shoaf
Brown
Perry
Thompson
Termination of
Employment by the
Employer Other Than
for “Cause,” Death
or Disability, or by
the Executive for
“Good Reason” ($)(2)
Termination of
Employment
because of Death or
Disability ($)(3)
Termination by the
Executive Other
Than for “Good
Reason” ($)(4)
Continued
Employment
Following Change
of Control ($)(5)
1,854,748
899,007
1,022,274
469,520
467,528
2,113,512
1,024,684
1,103,568
535,150
535,150
3,462,984
1,460,013
1,395,404
—
—
12,905,340
5,725,779
6,026,267
2,370,660
2,407,733
1,854,748
899,007
1,022,274
469,520
467,528
2,113,512
1,024,684
1,103,568
535,150
535,150
—
—
—
—
—
4,768,260
2,245,243
2,472,129
1,231,545
1,229,553
1,854,748
899,007
1,022,274
469,520
467,528
2,113,512
1,024,684
1,103,568
535,150
535,150
—
—
—
—
—
4,768,260
2,245,243
2,472,129
1,231,545
1,229,553
1,854,748
899,007
1,022,274
469,520
467,528
2,113,512
1,024,684
1,103,568
535,150
535,150
—
—
—
—
—
4,768,260
2,245,243
2,472,129
1,231,545
1,229,553
(1) Per SEC regulations, for purposes of this analysis we assumed each NEO’s compensation at the time of each
triggering event to be as stated below. The listed salary is the NEO’s actual annualized rate of pay as of
December 31, 2016. The listed bonus amount represents the highest bonus earned by the executive with respect to
any of the fiscal years 2014, 2015 and 2016 (the three years prior to the date of the assumed change of control):
Name
Annual Salary ($)
Bonus ($)
Barron
Shoaf
Brown
Perry
Thompson
575,000
349,700
376,700
275,800
275,800
800,000
321,552
346,287
226,875
226,875
(2) The change of control severance agreements provide that if the employer terminates the NEO’s employment (other
than for “cause,” death or “disability,” as defined in the agreements) or if the NEO terminates his or her employment
for “good reason,” as defined in the agreements, the NEO is generally entitled to receive the following:
(A) a lump sum cash payment equal to the sum of:
(i) accrued and unpaid compensation through the date of termination, including a pro-rata annual bonus based on
the highest bonus from the past three years;
(ii) the NEO’s severance multiple multiplied by the sum of the NEO’s annual base salary plus the NEO’s highest
annual bonus from the past three years;
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(iii) the amount of the excess of the actuarial present value of the pension benefits (qualified and nonqualified) the
NEO would have received for an additional number of years of service equal to the NEO’s severance multiple
over the actuarial present value of the NEO’s actual pension benefits; and
(iv) the equivalent of employer contributions under the tax-qualified and supplemental defined contribution plans
for the number of years equal to the NEO’s severance multiple;
(B) continued welfare benefits for a number of years equal to the NEO’s severance multiple; and
(C) vesting of all outstanding equity incentive awards on the date of the change of control, as described above.
(3) If the NEO’s employment is terminated by reason of his or her death or disability, then his or her estate or
beneficiaries will be entitled to receive a lump sum cash payment equal to any accrued and unpaid salary and
vacation pay plus a bonus equal to the highest bonus earned by the NEO in the prior three years (prorated to the date
of termination). In addition, in the case of disability, the NEO would be entitled to any disability and related benefits
at least as favorable as those provided by us under our plans and programs during the 120-days prior to the NEO’s
termination of employment. In addition, all outstanding equity incentive awards will automatically vest on the date
of the change of control, as described above.
(4) If the NEO voluntarily terminates his or her employment other than for “good reason,” then he or she will be
entitled to a lump sum cash payment equal to any accrued and unpaid salary and vacation pay plus a bonus equal to
the highest bonus earned by the NEO in the prior three years (prorated to the date of termination). In addition, all
outstanding equity incentive awards will automatically vest on the date of the change of control, as described above.
(5) The change of control severance agreements provide for a three-year term of employment following a change of
control. The agreements generally provide that the NEO will continue to receive a salary and bonus at least as
favorable as the highest salary received during the past 12 months and the highest bonus received during the past
three years and will continue to receive benefits on terms at least as favorable as in effect prior to the change of
control. Accordingly, no additional amounts are shown for salary, pension and excess pension benefits, contributions
under defined contribution plans and health and welfare plan benefits because those amounts would remain as in
effect at the time of a change of control. The amount shown as bonus reflects each NEO’s highest bonus during the
past three years. In addition, all outstanding equity incentive awards will automatically vest on the date of the
change of control, as described above.
(6) The NEO is entitled to coverage under the welfare benefit plans (e.g., health, dental, etc.) for a number of years
following the date of termination equal to the NEO’s severance multiple.
(7) The amounts stated in the table represent the gross value of previously unvested restricted units, derived by
multiplying (x) the number of units whose restrictions lapsed because of the change of control, times (y) (as
applicable) $49.80 (the closing price of NuStar Energy’s common units on the NYSE on December 30, 2016, the
last trading day of 2016) or $28.90 (the closing price of NuStar GP Holdings’ common units on the NYSE on
December 30, 2016, the last trading day of 2016).
(8) The amounts stated in the table represent the product of (x) the number of performance units whose vesting was
accelerated because of the change of control, times (y) 200%, times (z) $49.80 (the closing price of NuStar Energy’s
common units on the NYSE on December 30, 2016, the last trading day of 2016).
(9) If any payment or benefit to Mr. Barron, Mr. Shoaf or Ms. Brown is determined to be subject to an excise tax under
Section 4999 of the Code, the impacted NEO is entitled to receive an additional payment to adjust for the
incremental tax cost of the payment or benefit. However, if it is determined that the NEO is entitled to receive an
additional payment to adjust for the incremental tax cost but the value of all payments to the NEO does not exceed
100% of 2.99 times the NEO’s “base amount” (as defined by Section 280G(b)(3) of the Code) (the Safe Harbor
Amount), the additional payment will not be made and the amount payable to the NEO will be reduced so that the
aggregate value of all payments equals the Safe Harbor Amount.
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DIRECTOR COMPENSATION
FOR THE YEAR ENDED DECEMBER 31, 2016
The following table provides a summary of compensation paid for the year ended December 31, 2016 to the directors who
served on the Board during 2016. The table shows amounts earned by such persons for services rendered to NuStar GP, LLC
in all capacities in which they served during 2016. Robert J. Munch was appointed as a member of the Board on January 26,
2016.
Fees Earned
or
Paid in Cash
($)(1)
134,500
(4)
Unit Awards
($)(2)
99,957
(4)
99,500
114,500
77,374
94,500
74,991
74,991
149,975
74,991
Name
William E. Greehey
Bradley C. Barron
J. Dan Bates
Dan J. Hill
Robert J. Munch
W. Grady Rosier
Change in Pension
Value and
Nonqualified
Deferred
Compensation
Earnings
($)(3)
Non-Equity
Incentive Plan
Compensation
($)(3)
All Other
Compensation
($)
TOTAL
($)
N/A
(4)
N/A
N/A
N/A
N/A
N/A
(4)
N/A
N/A
N/A
N/A
— 234,457
(4)
(4)
— 174,491
— 189,491
— 227,349
— 169,491
(1) The amounts disclosed in this column exclude reimbursement for expenses for transportation to and from Board
meetings and lodging while attending meetings.
(2) The amounts reported for Messrs. Greehey, Bates, Hill and Rosier represent the grant date fair value for the
November 16, 2016 grant of restricted NuStar Energy units to them as non-employee directors for the fiscal year
ended December 31, 2016 (2,182 restricted units for Mr. Greehey, as Chairman, and 1,637 restricted units for each
of Messrs. Bates, Hill and Rosier) based on the closing price of NuStar Energy’s common units on the NYSE on
November 16, 2016 ($45.81). The amount reported for Mr. Munch represents the grant date fair value for his
January 26, 2016 grant of 2,469 restricted NuStar Energy units upon joining the Board and his November 16, 2016
grant of 1,637 restricted NuStar Energy units as a non-employee director for the fiscal year ended December 31,
2016, based on the closing price of NuStar Energy’s common units on the NYSE on January 26, 2016 ($30.37) and
November 16, 2016 ($45.81), respectively. Please see “Compensation Discussion and Analysis-Impact of
Accounting and Tax Treatments-Accounting Treatment” above in this Item 11 for information regarding the
assumptions made in the valuation.
As of December 31, 2016, each director listed in the table above held the following aggregate number of NuStar
Energy restricted unit awards. None of the directors listed in the table above had outstanding unit options as of
December 31, 2016.
Name
Aggregate # of Restricted Units
Greehey
Barron
Bates
Hill
Munch
Rosier
4,317
*
3,237
3,237
4,106
3,237
* Mr. Barron’s aggregate holdings are disclosed above in the Outstanding Equity Awards at December 31,
2016 table in this Item 11.
(3) Non-employee directors do not participate in these plans.
(4) Mr. Barron was not compensated for his service as a director of NuStar GP, LLC. His compensation for his services
as President and CEO are included above in the Summary Compensation Table.
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Directors who are our employees receive no compensation (other than reimbursement of expenses) for serving as directors.
The compensation structure for our non-employee directors consists of the following components: (1) an annual cash
retainer; (2) an annual restricted unit grant; (3) an additional cash payment for each meeting attended in-person and
telephonically; (4) an additional annual cash retainer for each committee chair; (5) an additional annual retainer for the
Chairman of the Board, which includes both cash and restricted units; and (6) an additional annual cash retainer for the lead
director, each as set forth in the table below.
Non-Employee Director Compensation Component
Amount
Annual Cash Retainer ($)
Annual Restricted Unit Grant ($ value of restricted units)
Per Meeting Fees (in-person attendance) ($)
Per Meeting Fees (telephonic attendance) ($)
Annual Audit and Compensation Committee Chair Additional Retainers ($)
Annual Nominating, Governance and Conflicts Committee Chair Additional Retainer ($)
Annual Chairman of the Board Retainer ($25,000 value in restricted units/$50,000 cash)
Annual Lead Director Additional Retainer ($)
60,000
75,000
1,500
500
15,000
10,000
75,000
15,000
As described above, we supplement the cash compensation paid to non-employee directors with an annual grant of restricted
NuStar Energy units that vests in equal annual installments over a three-year period. We believe this annual grant of restricted
units increases the non-employee directors’ identification with the interests of NuStar Energy’s unitholders through
ownership of NuStar Energy common units. Upon a non-employee director’s initial election to the Board, the director will
receive a grant of restricted units.
In the event of a “change of control” as defined in the 2000 LTIP, all unvested restricted units previously granted immediately
become vested. The 2000 LTIP also contains anti-dilution provisions providing for an adjustment in the number of restricted
units that have been granted to prevent dilution of benefits in the event there is a change in the capital structure of NuStar
Energy that affects the NuStar Energy units.
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
There are no compensation committee interlocks. The members of our Compensation Committee are Mr. Hill (Chairman),
Mr. Bates, Mr. Munch and Mr. Rosier. None of the members of our Compensation Committee have served as an officer or
employee of ours. Furthermore, except for compensation arrangements disclosed in this Annual Report on Form 10-K,
NuStar Energy has not participated in any contracts, loans, fees or awards, nor does it have financial interests, direct or
indirect, with any Compensation Committee member. In addition, none of NuStar Energy’s management or Board members
are aware of any means, directly or indirectly, by which a Compensation Committee member could receive a material benefit
from NuStar Energy.
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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED
UNITHOLDER MATTERS
SECURITY OWNERSHIP OF MANAGEMENT AND DIRECTORS
The following table sets forth information as of February 20, 2017 regarding NuStar Energy common units and NuStar GP
Holdings common units beneficially owned (or deemed beneficially owned) by the directors, executive officers and all
directors and executive officers of NuStar GP, LLC as a group. Unless otherwise indicated in the notes to the table, each of the
named persons and members of the group has sole voting and investment power with respect to the common units shown and
none of the common units shown are pledged as security. Except as indicated with respect to Mr. Munch in the notes to the
table, none of the named persons or members of the group beneficially owns (or is deemed to beneficially own) any NuStar
Energy 8.50% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units.
Name of
Beneficial Owner (1)
William E. Greehey (5)
Bradley C. Barron
J. Dan Bates (6)
Dan J. Hill (7)
Robert J. Munch (8)
W. Grady Rosier (9)
Mary Rose Brown
Thomas R. Shoaf
Jorge A. del Alamo
Amy L. Perry (10)
Karen M. Thompson
Common
Units
Beneficially
Owned (2)
3,069,846
47,659
29,543
21,585
823
23,256
56,286
22,795
12,329
3,476
13,600
All directors and executive
officers as a group (11 people)
3,301,198
NuStar Energy
NuStar GP Holdings
Percentage
of Common
Units
Beneficially
Owned (2)
Common Units
Beneficially
Owned (2)
3.90%
9,037,825
*
*
*
*
*
*
*
*
*
*
27,047
4,000
27,000
—
20,000
44,889
10,294
564
505
544
4.20%
9,172,668
Percentage of
Common
Units
Beneficially
Owned (2)
21.04%
*
*
*
*
*
*
*
*
*
*
21.36%
Restricted
Units (4)
7,364
19,577
—
—
—
—
10,764
9,485
4,163
4,334
4,334
60,021
Restricted
Units (3)
4,317
25,883
3,237
3,237
3,283
3,237
14,281
12,548
6,612
6,913
6,873
90,421
* Indicates that the percentage of beneficial ownership does not exceed 1% of the class.
(1) The business address for all beneficial owners listed above is 19003 IH-10 West, San Antonio, Texas 78257.
(2) As of February 20, 2017, 78,655,818 NuStar Energy common units and 42,951,749 NuStar GP Holdings common
units were outstanding. Beneficial ownership is calculated in accordance with Rule 13d-3 of the Securities Exchange
Act of 1934. Accordingly, the amounts and percentages of beneficial ownership shown in the table above do not
reflect any of the restricted units shown, which do not vest within 60 days.
(3) This column reflects restricted units issued under the long-term incentive plans of NuStar GP, LLC. Restricted units
granted under NuStar GP, LLC’s long-term incentive plans are rights to receive NuStar Energy common units upon
vesting and, as such, may not be disposed of or voted until vested. The restricted units do not vest within 60 days after
February 20, 2017 and, accordingly, are not included in the calculation of beneficial ownership pursuant to Rule
13d-3.
(4) This column reflects phantom units (which we refer to as “restricted units” for purposes of this table) issued under the
long-term incentive plan of NuStar GP Holdings. Restricted units granted under NuStar GP Holdings’ long-term
incentive plan are rights to receive NuStar GP Holdings’ common units upon vesting and, as such, may not be
disposed of or voted until vested. The restricted units do not vest within 60 days after February 20, 2017 and,
accordingly, are not included in the calculation of beneficial ownership pursuant to Rule 13d-3.
(5) The number of NuStar GP Holdings common units shown as beneficially owned by Mr. Greehey includes 385,889
common units owned indirectly by Mr. Greehey through a limited liability company.
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(6) The number of NuStar Energy common units shown as beneficially owned by Mr. Bates includes 24,962 common
units owned indirectly by Mr. Bates through a trust. The number of NuStar GP Holdings common units shown as
beneficially owned by Mr. Bates reflects 4,000 common units owned indirectly by Mr. Bates through a trust.
(7) The number of NuStar Energy common units shown as beneficially owned by Mr. Hill includes 600 common units
owned indirectly by Mr. Hill through his spouse. Pursuant to Rule 13d-4 of the Securities Exchange Act of 1934, Mr.
Hill disclaims beneficial ownership of 2,000 of the NuStar GP Holdings common units reflected as beneficially owned
by him in the table above, which were purchased by a trust and may be deemed to be owned indirectly by Mr. Hill.
(8) In addition to the NuStar Energy common units shown as beneficially owned by Mr. Munch, Mr. Munch beneficially
owns 1,000 NuStar Energy 8.50% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units,
which is less than 1% of the class.
(9) The number of NuStar Energy common units shown as beneficially owned by Mr. Rosier includes 19,000 common
units owned indirectly by Mr. Rosier through a trust.
(10) When Ms. Perry was divorced in September 2012, Ms. Perry agreed to give her ex-spouse a portion of any NuStar
Energy units she would receive in the future upon vesting of restricted units that were granted to her prior to
September 2012 and remained outstanding at the time of the divorce.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
The following table sets forth information as of December 31, 2016 regarding each entity known to us to be the beneficial
owner of more than 5% of NuStar Energy’s outstanding common units, and is based solely upon reports filed by such entities
with the SEC.
Name and Address of Beneficial Owner
Common Units
Beneficially Owned
Percentage of Common Units
Beneficially Owned(1)
NuStar GP Holdings (2)
OppenheimerFunds, Inc. (3)
ALPS Advisors, Inc. (4)
Harvest Fund Advisors LLC (5)
Center Coast Capital Advisors, LP (6)
10,214,626
6,955,668
4,393,371
4,219,205
4,194,921
12.99%
8.85%
5.59%
5.37%
5.34%
(1) As of December 31, 2016, there were 78,616,228 NuStar Energy common units issued and outstanding.
(2) As of December 31, 2016, NuStar GP Holdings owns these NuStar Energy common units through its wholly owned
subsidiaries, NuStar GP, LLC and Riverwalk Holdings, LLC. NuStar GP Holdings controls voting and investment
power over the common units through these wholly owned subsidiaries. NuStar GP Holdings’ business address is
19003 IH-10 West, San Antonio, Texas 78257.
(3) As reported on a Schedule 13G/A filed on January 31, 2017, OppenheimerFunds, Inc. (OFI) is an investment adviser
that may be deemed to beneficially own, and has shared voting and dispositive power with respect to, 6,955,668
common units. The 6,955,668 common units that OFI may be deemed to beneficially own include 5,340,776 common
units that Oppenheimer SteelPath MLP Income Fund (OSP), an investment company, may be deemed to beneficially
own. OSP has shared voting and dispositive power with respect to the 5,340,776 common units. OFI disclaims
beneficial ownership of the common units pursuant to Rule 13d-4 of the Securities Exchange Act of 1934. OFI’s
business address is 225 Liberty Street, New York, New York 10281. OSP’s business address is 6803 S. Tucson Way,
Centennial, Colorado 80112.
(4) As reported on a Schedule 13G/A filed on January 26, 2017, ALPS Advisors, Inc. (AAI) is an investment adviser that
may be deemed to beneficially own, and has shared voting and dispositive power with respect to, 4,393,371 common
units. The 4,393,371 common units that AAI may be deemed to beneficially own include 4,375,221 common units that
Alerian MLP ETF (Alerian), an investment company, may be deemed to beneficially own. Alerian has shared voting
and dispositive power with respect to the 4,375,221 common units. AAI disclaims beneficial ownership of the
common units pursuant to Rule 13d-4 of the Securities Exchange Act of 1934. The business address of AAI and
Alerian is 1290 Broadway, Suite 1100, Denver, Colorado 80203.
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(5) As reported on a Schedule 13G filed on February 10, 2017, Harvest Fund Advisors LLC (Harvest Fund) is an
investment adviser that, as of February 10, 2017, may be deemed to beneficially own, and has sole voting and
dispositive power with respect to, 4,219,205 common units. The business address of Harvest Fund is 100 W. Lancaster
Avenue, Suite 200, Wayne, Pennsylvania 19087.
(6) As reported on a Schedule 13G filed on January 9, 2017, Center Coast Capital Advisors, LP (Center Coast) is an
investment adviser that, as of January 9, 2017, may be deemed to beneficially own, and has shared voting and
dispositive power with respect to, 4,194,921 common units. The business address of Center Coast is 1600 Smith
Street, Suite 3800, Houston, Texas 77002.
EQUITY COMPENSATION PLAN INFORMATION
The following table sets forth information as of December 31, 2016 about equity compensation plans under which securities of
NuStar Energy are issuable, which are described in further detail in Note 24 of the Notes to Consolidated Financial Statements
in Item 8. “Financial Statements and Supplementary Data.”
Plan categories
Equity Compensation Plans
approved by security holders (2)
Equity Compensation Plans not
approved by security holders (3)
Number of securities to
be issued upon exercise of
outstanding unit options,
warrants and rights (#)
Weighted-average
exercise price of
outstanding unit
options, warrants
and rights ($) (1)
791,204
1,893
Number of securities
remaining for
future issuance
under equity
compensation plans (#)
990,018
—
—
—
(1) No value is included in this column because there were no unit options outstanding as of December 31, 2016 and
because restricted units and performance units do not have an exercise price.
(2) The information in this row relates to the 2000 LTIP. See the “Compensation Discussion and Analysis” section of
Item 11 above for further details regarding the 2000 LTIP.
(3) The information in this row relates to the 2003 Employee Unit Incentive Plan, which terminated on June 16, 2013.
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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
TRANSACTIONS WITH MANAGEMENT AND OTHERS
In January 2007, our Board adopted a written related person transaction policy that codifies our prior practice. For purposes of
the policy, a related person transaction is one that is not available to all employees generally or involves $10,000 or more when
aggregated with similar transactions. The policy requires that any related person transaction between NuStar Energy or NuStar
GP, LLC and: (1) any vice president, Section 16 officer or director; (2) any unitholder owning greater than 5% of NuStar
Energy, its controlled affiliates or NuStar GP Holdings; (3) any immediate family member of any officer or director; or (4) any
entity controlled by any of (1), (2) or (3) (or in which any of (1), (2) or (3) owns a 5% or greater ownership interest) must be
approved by the disinterested members of the Board. In addition, the policy requires that the officers and directors have an
affirmative obligation to inform and provide updates to our Corporate Secretary regarding his or her immediate family
members, as well as any entities in which he or she controls or owns 5% or more.
Please see “Potential Payments upon Termination or Change of Control” in Item 11 for a discussion of our change of control
severance agreements with the NEOs.
On December 10, 2007, NuStar Logistics, L.P., our wholly owned subsidiary, entered into a non-exclusive Aircraft Time
Sharing Agreement (the Time Share Agreement) with William E. Greehey, Chairman of our Board. The Time Share Agreement
provides that NuStar Logistics, L.P. will sublease the aircraft to Mr. Greehey on an “as needed and as available” basis, and will
provide a fully qualified flight crew for all of Mr. Greehey’s flights. Mr. Greehey will pay NuStar Logistics, L.P. an amount
equal to the maximum amount of expense reimbursement permitted in accordance with Section 91.501(d) of the Aeronautics
Regulations of the Federal Aviation Administration and the Department of Transportation, which expenses include and are
limited to: fuel oil, lubricants and other additives; travel expenses of the crew, including food, lodging and ground
transportation; hangar and tie down costs away from the aircraft’s base of operation; insurance obtained for the specific flight;
landing fees, airport taxes and similar assessments; customs, foreign permit and similar fees directly related to the flight; in-
flight food and beverages; passenger ground transportation; flight planning and weather contract services; and an additional
charge equal to 100% of the costs of the fuel oil, lubricants and other additives. The Time Share Agreement had an initial term
of two years, and automatically renews for one-year terms until terminated by either party. The Time Share Agreement was
approved by the disinterested members of the Board on December 5, 2007. The Time Share Agreement was amended, as of
September 4, 2009, to reflect the addition of another aircraft.
On April 24, 2008, the independent directors of NuStar GP, LLC approved the adoption of a Services Agreement, effective
January 1, 2008, between NuStar GP, LLC and NuStar Energy (the Services Agreement). Pursuant to the Services Agreement,
NuStar GP, LLC historically furnished all services necessary for the conduct of the business of NuStar Energy, and NuStar
Energy reimbursed NuStar GP, LLC for all payroll and related benefit costs, including pension and unit-based compensation
costs, other than the expenses allocated to NuStar GP Holdings. The expenses allocated to NuStar GP Holdings under the
Services Agreement equaled to $1.1 million (as adjusted), plus 1.0% of NuStar GP, LLC’s domestic employee bonus and unit
compensation expense for the applicable fiscal year, subject to adjustment (1) by an annual amount equal to NuStar GP, LLC’s
annual merit increase percentage for the most recently completed contract year and (2) for changed levels of services due to
expansion of operations through, among other things, expansion of operations, acquisitions or the construction of new
businesses or assets. On March 1, 2016, NuStar GP, LLC transfered and assigned to NuStar Services Co, a wholly owned
subsidiary of NuStar Energy, employment of all of NuStar GP, LLC’s employees. Our executive officers continue to serve as
officers of NuStar GP Holdings and NuStar GP, LLC, and also serve as officers of NuStar Services Co and other NuStar Energy
subsidiaries. In connection with the transfer and assignment, we amended and restated the Services Agreement (the Amended
and Restated Services Agreement) such that, beginning March 1, 2016, NuStar GP Holdings and NuStar Energy receive all
management and administrative services from NuStar Services Co. NuStar Energy reimburses NuStar Services Co for all
services provided to NuStar Energy, including payroll and benefit costs, as well as NuStar Energy unit-based compensation
costs. NuStar GP Holdings pays NuStar Services Co an administrative services fee of $1.0 million per year, subject to
adjustment (1) by an annual amount equal to NuStar Services Co’s annual merit increase percentage for the most recently
completed fiscal year and (2) for changed levels of services due to expansion of operations through acquisitions, construction
of new businesses or assets or otherwise. For 2016, the administrative services fee was $1.0 million. Beginning March 1, 2016,
NuStar GP Holdings no longer pays 1.0% of our domestic bonus and unit compensation expenses. Instead, NuStar GP Holdings
retains the expense associated with any NuStar GP Holdings common unit awards or other compensation that it provides to its
officers.
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John D. Greehey, an employee, is the son of Mr. Greehey. As such, he is deemed to be a “related person” under Item 404(a) of
the SEC’s Regulation S-K. Mr. J. Greehey is a Vice President of certain subsidiaries of NuStar Energy. In 2016, Mr. J. Greehey
did not attend any Board or Committee meetings. The aggregate value of compensation paid to Mr. J. Greehey in 2016 was less
than $500,000. There were no material differences between the compensation paid to Mr. J. Greehey and the compensation paid
to any other employees who hold analogous positions.
RIGHTS OF NUSTAR GP HOLDINGS
Due to its ownership of NuStar GP, LLC and Riverwalk Holdings, LLC, as of December 31, 2016, NuStar GP Holdings
indirectly owned:
•
•
•
the general partner interest in NuStar Energy, through its indirect 100% ownership interest in Riverwalk Logistics,
L.P.;
100% of the incentive distribution rights issued by us, which entitle NuStar GP Holdings to receive increasing
percentages of the cash we distribute, currently at the maximum percentage of 23%; and
10,214,626 NuStar Energy common units.
Certain of our officers also are officers of NuStar GP Holdings. Our Chairman, Mr. Greehey, also is the Chairman of Board
and, as of December 31, 2016, beneficially owned approximately 21% of the common units of NuStar GP Holdings. NuStar GP
Holdings appoints NuStar GP, LLC’s directors. NuStar GP, LLC’s board is responsible for overseeing NuStar GP, LLC’s role as
the owner of the general partner of NuStar Energy. NuStar GP Holdings must also approve matters that have or would
reasonably be expected to have a material effect on NuStar GP Holdings’ interests as one of our major unitholders.
NuStar Energy’s partnership agreement requires that NuStar GP, LLC maintain a Conflicts Committee, composed entirely of
independent directors, to review and resolve certain potential conflicts of interest between Riverwalk Logistics, L.P. and its
affiliates, on the one hand, and NuStar Energy, on the other.
DIRECTOR INDEPENDENCE
Our business is managed under the direction of the Board of NuStar GP, LLC, the general partner of Riverwalk Logistics, L.P.,
the general partner of NuStar Energy. The Board conducts its business through meetings of the Board and its committees. The
Board has standing Audit, Compensation and Nominating/Governance & Conflicts Committees. Each committee has a written
charter. During 2016, the Board held six meetings, the Audit Committee held eight meetings, the Compensation Committee
held four meetings and the Nominating/Governance & Conflicts Committee held one meeting. No member of the Board
attended less than 75% of the meetings of the Board and committees during the period in which he was a member during 2016.
INDEPENDENT DIRECTORS
The Board has one member of management, Mr. Barron, President and CEO, and five non-management directors. As a limited
partnership, NuStar Energy is not required to have a majority of independent directors. However, the Board has determined that
four of five of its current non-management directors meet the independence requirements of the NYSE listing standards as set
forth in the NYSE Listed Company Manual. The independent directors are: Mr. Bates, Mr. Hill, Mr. Munch and Mr. Rosier.
Mr. Greehey, Chairman of the Board, also serves as the Chairman of the NuStar GP Holdings board of directors and, as of
December 31, 2016, beneficially owned approximately 21% of the common units of NuStar GP Holdings. Mr. Greehey is not
an independent director under the NYSE’s listing standards.
Mr. Barron has been President and CEO of NuStar GP, LLC since January 2014. Mr. Barron also serves as President and CEO
of NuStar GP Holdings. As a member of management, Mr. Barron is not an independent director under the NYSE’s listing
standards.
The Audit, Compensation and Nominating/Governance & Conflicts Committees of the Board are each composed entirely of
directors who meet the independence requirements of the NYSE listing standards. Each member of the Audit Committee also
meets the additional independence standards for Audit Committee members set forth in the regulations of the SEC. For further
information about the committees, see also Item 10 and Item 11 above.
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INDEPENDENCE DETERMINATIONS
Under the NYSE’s listing standards, no director qualifies as independent unless the Board affirmatively determines that the
director has no material relationship with NuStar Energy. Based upon information requested annually from and provided by
each director concerning their background, employment and affiliations, including commercial, industrial, banking, consulting,
legal, accounting, charitable and familial relationships, the Board has determined that, other than being a director of NuStar GP,
LLC, a unitholder of NuStar Energy and/or a unitholder of NuStar GP Holdings, each of the independent directors named
above has either no relationship with NuStar Energy, either directly or as a partner, equityholder or officer of an organization
that has a relationship with NuStar Energy, or has only immaterial relationships with NuStar Energy, and is therefore
independent under the NYSE’s listing standards.
As provided for under the NYSE listing standards, the Board has adopted categorical standards or guidelines to assist the Board
in making its independence determinations with respect to each director. Under the NYSE listing standards, immaterial
relationships that fall within the guidelines are not required to be disclosed in this Annual Report on Form 10-K.
A relationship falls within the guidelines adopted by the Board if it:
•
•
•
is not a relationship that would preclude a determination of independence under Section 303A.02(b) of the NYSE Listed
Company Manual;
consists of charitable contributions by NuStar Energy to an organization where a director is an executive officer and does
not exceed the greater of $1 million or 2% of the organization’s gross revenue in any of the last three years;
consists of charitable contributions by NuStar Energy to any organization with which a director, or any member of a
director’s immediate family, is affiliated as an officer, director or trustee pursuant to a matching gift program of NuStar
Energy and made on terms applicable to employees and directors generally, or is in amounts that do not exceed $250,000
per year; and
•
is not required to be disclosed in this Annual Report on Form 10-K.
Our Corporate Governance Guidelines contain the director qualification standards, including the guidelines listed above, and
are available on NuStar Energy’s website at www.nustarenergy.com (in the “Investors” section) or are available in print upon
request to NuStar GP, LLC’s Corporate Secretary at the address indicated on the cover page of this Annual Report on Form 10-
K or corporatesecretary@nustarenergy.com.
PRESIDING DIRECTOR/MEETINGS OF NON-MANAGEMENT DIRECTORS
The Board has designated Mr. Hill to serve as the Presiding Director for meetings of the non-management Board members
outside the presence of management.
COMMUNICATIONS WITH THE BOARD, NON-MANAGEMENT DIRECTORS OR PRESIDING DIRECTOR
Unitholders and other interested parties may communicate with the Board, the non-management directors or the Presiding
Director by sending a written communication in an envelope addressed to “Board of Directors,” “Non-Management Directors,”
or “Presiding Director” in care of NuStar GP, LLC’s Corporate Secretary at the address indicated on the cover page of this
Annual Report on Form 10-K or corporatesecretary@nustarenergy.com.
AVAILABILITY OF GOVERNANCE DOCUMENTS
NuStar Energy has posted its Corporate Governance Guidelines, Code of Business Conduct and Ethics, Code of Ethics for
Senior Financial Officers and the Charters of the Audit Committee, Compensation Committee and Nominating/Governance &
Conflicts Committee on NuStar Energy’s website at www.nustarenergy.com (in the “Investors” section). NuStar Energy’s
governance documents are available in print to any unitholder of record who makes a written request to NuStar Energy.
Requests must be directed to NuStar GP, LLC’s Corporate Secretary at the address indicated on the cover page of this Annual
Report on Form 10-K or corporatesecretary@nustarenergy.com.
162
Table of Contents
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
KPMG FEES
The aggregate fees for professional services rendered to us by KPMG for the years ended December 31, 2016 and 2015 were:
Category of Service
Audit fees (1)
Audit-related fees (2)
Tax fees
All other fees
Total
2016
2,633,321
—
—
—
2,633,321
$
$
2015
2,770,868
3,243
—
—
2,774,111
$
$
(1) Audit fees for 2016 and 2015 were for professional services rendered by KPMG in connection with the audits of our
annual financial statements for the years ended December 31, 2016 and 2015, respectively, included in our Annual
Reports on Form 10-K, reviews of our interim financial statements included in our Quarterly Reports on Form 10-Q,
the audit of the effectiveness of our internal control over financial reporting as of December 31, 2016 and 2015,
respectively, and related services that that are normally provided by the principal auditor (e.g., comfort letters and
assistance with review of documents filed with the SEC).
(2) Audit-related fees for 2015 were for assurance and related services rendered by KPMG that are reasonably related to
the performance of the audit or review of our financial statements and are not reported under “Audit fees.”
AUDIT COMMITTEE PRE-APPROVAL POLICY
The Audit Committee has adopted a pre-approval policy to address the pre-approval of all services to be rendered to us by our
independent auditor and ensure that the provision of any non-audit services does not impair the auditor’s independence. None
of the services (described above) for 2016 or 2015 provided by KPMG were approved by the Audit Committee pursuant to the
pre-approval waiver contained in paragraph (c)(7)(i)(C) of Rule 2-01 of Regulation S-X.
163
Table of Contents
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
PART IV
(a)
(1) Financial Statements. The following consolidated financial statements of NuStar Energy L.P. and its subsidiaries are
included in Part II, Item 8 of this Form 10-K:
Management’s Report on Internal Control over Financial Reporting
Reports of independent registered public accounting firm (KPMG LLP)
Consolidated Balance Sheets as of December 31, 2016 and 2015
Consolidated Statements of Income for the Years Ended December 31, 2016, 2015 and 2014
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2016, 2015 and 2014
Consolidated Statements of Cash Flows for the Years Ended December 31, 2016, 2015 and 2014
Consolidated Statements of Partners’ Equity for the Years Ended December 31, 2016, 2015 and 2014
Notes to Consolidated Financial Statements
(2) Financial Statement Schedules and Other Financial Information. No financial statement schedules are submitted
because either they are inapplicable or because the required information is included in the consolidated financial
statements or notes thereto.
(3) Exhibits.
The following are filed or furnished, as applicable, as part of this Form 10-K:
Exhibit
Number
Description
Incorporated by Reference
to the Following Document
3.01
3.02
3.03
3.04
3.05
3.06
3.07
3.08
3.09
3.10
Amended and Restated Certificate of Limited
Partnership of Shamrock Logistics, L.P., effective
January 1, 2002
NuStar Energy L.P.’s Annual Report on Form 10-K
for year ended December 31, 2001 (File No.
001-16417), Exhibit 3.3
Amendment to Certificate of Limited Partnership
of Valero L.P., dated March 21, 2007 and effective
April 1, 2007
NuStar Energy L.P.’s Current Report on Form 8-K
filed March 27, 2007 (File No. 001-16417), Exhibit
3.01
Fourth Amended and Restated Agreement of
Limited Partnership of NuStar Energy L.P., dated
as of November 25, 2016
NuStar Energy L.P.’s Current Report on Form 8-K
filed November 25, 2016 (File No. 001-16417),
Exhibit 3.1
Amended and Restated Certificate of Limited
Partnership of Shamrock Logistics Operations,
L.P., dated as of January 7, 2002 and effective
January 8, 2002
NuStar Energy L.P.’s Annual Report on Form 10-K
for year ended December 31, 2001 (File No.
001-16417), Exhibit 3.8
Certificate of Amendment to Certificate of Limited
Partnership of Valero Logistics Operations, L.P.,
dated March 21, 2007 and effective April 1, 2007
NuStar Energy L.P.’s Quarterly Report on Form 10-
Q for quarter ended March 31, 2007 (File No.
001-16417), Exhibit 3.03
Certificate of Amendment to Certificate of Limited
Partnership of NuStar Logistics, L.P., dated and
effective as of March 18, 2014
NuStar Energy L.P.’s Annual Report on Form 10-K
for year ended December 31, 2014 (File No.
001-16417), Exhibit 3.09
Second Amended and Restated Agreement of
Limited Partnership of Shamrock Logistics
Operations, L.P., dated as of April 16, 2001
NuStar Energy L.P.’s Annual Report on Form 10-K
for year ended December 31, 2001 (File No.
001-16417), Exhibit 3.9
First Amendment to Second Amended and Restated
Agreement of Limited Partnership of Shamrock
Logistics Operations, L.P., effective as of April 16,
2001
Second Amendment to Second Amended and
Restated Agreement of Limited Partnership of
Shamrock Logistics Operations, L.P., dated as of
January 7, 2002
Certificate of Limited Partnership of Riverwalk
Logistics, L.P., dated as of June 5, 2000
NuStar Energy L.P.’s Quarterly Report on Form 10-
Q for quarter ended June 30, 2001 (File No.
001-16417), Exhibit 4.1
NuStar Energy L.P.’s Annual Report on Form 10-K
for year ended December 31, 2001 (File No.
001-16417), Exhibit 3.10
NuStar Energy L.P.’s Registration Statement on
Form S-1 filed August 14, 2000 (File No.
333-43668), Exhibit 3.7
164
Table of Contents
3.11
3.12
3.13
3.14
3.15
3.16
3.17
3.18
4.01
4.02
4.03
4.04
4.05
First Amended and Restated Limited Partnership
Agreement of Riverwalk Logistics, L.P., dated as of
April 16, 2001
NuStar Energy L.P.’s Annual Report on Form 10-K
for year ended December 31, 2001 (File No.
001-16417), Exhibit 3.16
Certificate of Formation of Shamrock Logistics GP,
LLC, dated as of December 7, 1999
NuStar Energy L.P.’s Registration Statement on
Form S-1 filed August 14, 2000 (File No.
333-43668), Exhibit 3.9
Certificate of Amendment to Certificate of
Formation of Shamrock Logistics GP, LLC, dated
as of December 31, 2001
NuStar Energy L.P.’s Annual Report on Form 10-K
for year ended December 31, 2001 (File No.
001-16417), Exhibit 3.14
Certificate of Amendment to Certificate of
Formation of Valero GP, LLC, dated March 21,
2007 and effective April 1, 2007
NuStar Energy L.P.’s Quarterly Report on Form 10-
Q for quarter ended March 31, 2007 (File No.
001-16417), Exhibit 3.02
First Amended and Restated Limited Liability
Company Agreement of Shamrock Logistics GP,
LLC, dated as of June 5, 2000
NuStar Energy L.P.’s Amendment No. 5 to
Registration Statement on Form S-1 filed March
29, 2001 (File No. 333-43668), Exhibit 3.10
First Amendment to First Amended and Restated
Limited Liability Company Agreement of
Shamrock Logistics GP, LLC, effective as of
December 31, 2001
NuStar Energy L.P.’s Annual Report on Form 10-K
for year ended December 31, 2001 (File No.
001-16417), Exhibit 3.15
Second Amendment to First Amended and Restated
Limited Liability Company Agreement of Valero
GP, LLC, effective as of June 1, 2006
NuStar Energy L.P.’s Annual Report on Form 10-K
for year ended December 31, 2014 (File No.
001-16417), Exhibit 3.20
NuStar Energy L.P.’s Quarterly Report on Form 10-
Q for quarter ended June 30, 2016 (File No.
001-16417), Exhibit 3.01
NuStar Energy L.P.’s Current Report on Form 8-K
filed July 15, 2002 (File No. 001-16417),
Exhibit 4.1
NuStar Energy L.P.’s Quarterly Report on Form 10-
Q for quarter ended June 30, 2005 (File No.
001-16417), Exhibit 4.02
NuStar Energy L.P.’s Annual Report on Form 10-K
for year ended December 31, 2008 (File No.
001-16417), Exhibit 4.05
NuStar Energy L.P.’s Current Report on Form 8-K
filed April 4, 2008 (File No. 001-16417),
Exhibit 4.2
NuStar Energy L.P.’s Current Report on Form 8-K
filed August 16, 2010 (File No. 001-16417),
Exhibit 4.3
Third Amendment to First Amended and Restated
Limited Liability Company Agreement of NuStar
GP, LLC, dated as of July 29, 2016 and effective as
of March 21, 2007
Indenture, dated as of July 15, 2002, among Valero
Logistics Operations, L.P., as Issuer, Valero L.P., as
Guarantor, and The Bank of New York, as Trustee,
relating to Senior Debt Securities
Third Supplemental Indenture, dated as of July 1,
2005, to Indenture dated as of July 15, 2002, as
amended and supplemented, among Valero
Logistics Operations, L.P., Valero L.P., Kaneb Pipe
Line Operating Partnership, L.P., and The Bank of
New York Trust Company, N.A.
Instrument of Resignation, Appointment and
Acceptance, dated March 31, 2008, among NuStar
Logistics, L.P., NuStar Energy L.P., Kaneb Pipeline
Operating Partnership, L.P., The Bank of New York
Trust Company N.A., and Wells Fargo Bank,
National Association
Fourth Supplemental Indenture, dated as of April 4,
2008, to Indenture dated as of July 15, 2002,
among NuStar Logistics L.P., as Issuer, NuStar
Energy L.P., as Guarantor, NuStar Pipeline
Operating Partnership L.P., as Affiliate Guarantor,
and Wells Fargo Bank, National Association, as
Successor Trustee
Fifth Supplemental Indenture, dated as of August
12, 2010, to Indenture dated as of July 15, 2002,
among NuStar Logistics, L.P., as Issuer, NuStar
Energy L.P., as Guarantor, NuStar Pipeline
Operating Partnership L.P., as Affiliate Guarantor,
and Wells Fargo Bank, National Association, as
Successor Trustee
165
Table of Contents
4.06
4.07
4.08
4.09
10.01
10.02
10.03
10.04
10.05
10.06
Sixth Supplemental Indenture, dated as of February
2, 2012, to Indenture dated as of July 15, 2002,
among NuStar Logistics, L.P., as Issuer, NuStar
Energy L.P., as Guarantor, NuStar Pipeline
Operating Partnership L.P., as Affiliate Guarantor,
and Wells Fargo Bank, National Association, as
Successor Trustee
Seventh Supplemental Indenture, dated as of
August 19, 2013, among NuStar Logistics, L.P., as
Issuer, NuStar Energy L.P., as Guarantor, NuStar
Pipeline Operating Partnership L.P., as Affiliate
Guarantor, and Wells Fargo Bank, National
Association, as Successor Trustee
Indenture, dated as of January 22, 2013, among
NuStar Logistics, L.P., as Issuer, NuStar Energy
L.P., as Guarantor, and Wells Fargo Bank, National
Association, as Trustee, relating to Subordinated
Debt Securities
First Supplemental Indenture, dated as of January
22, 2013, among NuStar Logistics, L.P., as Issuer,
NuStar Energy L.P., as Parent Guarantor, NuStar
Pipeline Operating Partnership L.P., as Affiliate
Guarantor, and Wells Fargo Bank, National
Association, as Trustee
Amended and Restated 5-Year Revolving Credit
Agreement, dated as of October 29, 2014, among
NuStar Logistics, L.P., NuStar Energy L.P., the
Lenders party thereto and JPMorgan Chase Bank,
N.A., as Administrative Agent, SunTrust Bank and
Mizuho Bank, Ltd., as Co-Syndication Agents,
Wells Fargo Bank, National Association and PNC
Bank, National Association, as Co-Documentation
Agents, and J.P. Morgan Securities LLC, SunTrust
Robinson Humphrey, Inc., Mizuho Bank, Ltd.,
Wells Fargo Securities, LLC and PNC Capital
Markets LLC, as Joint Bookrunners and Joint Lead
Arrangers
First Amendment to Amended and Restated 5-Year
Revolving Credit Agreement, dated as of March 19,
2015, among NuStar Logistics, L.P., NuStar Energy
L.P., JPMorgan Chase Bank, N.A., as
Administrative Agent, and the Lenders party
thereto
NuStar Energy L.P.’s Current Report on Form 8-K
filed February 7, 2012 (File No. 001-16417),
Exhibit 4.3
NuStar Energy L.P.’s Current Report on Form 8-K
filed August 23, 2013 (File No. 001-16417),
Exhibit 4.3
NuStar Energy L.P.’s Current Report on Form 8-K
filed January 22, 2013 (File No. 001-16417),
Exhibit 4.1
NuStar Energy L.P.’s Current Report on Form 8-K
filed January 22, 2013 (File No. 001-16417),
Exhibit 4.2
NuStar Energy L.P.’s Current Report on Form 8-K
filed October 31, 2014 (File No. 001-16417),
Exhibit 10.1
NuStar Energy L.P.’s Quarterly Report on Form 10-
Q for quarter ended June 30, 2015 (File No.
001-16417), Exhibit 10.01
Lease Agreement Between Parish of St. James,
State of Louisiana and NuStar Logistics, L.P. dated
as of July 1, 2010
NuStar Energy L.P.’s Current Report on Form 8-K
filed July 21, 2010 (File No. 001-16417), Exhibit
10.01
Letter of Credit Agreement dated June 5, 2012
among NuStar Logistics, L.P., NuStar Energy L.P.,
the Lenders party thereto and Mizuho Corporate
Bank, Ltd., as Issuing Bank and Administrative
Agent
First Amendment to Letter of Credit Agreement,
dated as of June 29, 2012, among NuStar Logistics,
L.P., NuStar Energy L.P., the Lenders party thereto
and Mizuho Corporate Bank, Ltd., as Issuing Bank
and Administrative Agent
Second Amendment to Letter of Credit Agreement,
dated as of January 17, 2013, among NuStar
Logistics, L.P., NuStar Energy L.P., the Lenders
party thereto and Mizuho Corporate Bank, Ltd., as
Issuing Bank and Administrative Agent
166
NuStar Energy L.P.’s Current Report on Form 8-K
filed June 12, 2012 (File No. 001-16417), Exhibit
10.01
NuStar Energy L.P.’s Current Report on Form 8-K
filed July 6, 2012 (File No. 001-16417), Exhibit
10.02
NuStar Energy L.P.’s Annual Report on Form 10-K
for year ended December 31, 2014 (File No.
001-16417), Exhibit 10.10
Table of Contents
10.07
10.08
10.09
10.10
10.11
10.12
10.13
10.14
10.15
10.16
10.17
Third Amendment to Letter of Credit Agreement,
dated as of March 8, 2013, among NuStar
Logistics, L.P., NuStar Energy L.P., the Lenders
party thereto and Mizuho Corporate Bank, Ltd., as
Issuing Bank and Administrative Agent
Fourth Amendment to Letter of Credit Agreement,
dated as of April 19, 2013, among NuStar
Logistics, L.P., NuStar Energy L.P., the Lenders
party thereto and Mizuho Corporate Bank, Ltd., as
Issuing Bank and Administrative Agent
Fifth Amendment to Letter of Credit Agreement,
dated as of April 23, 2014, among NuStar
Logistics, L.P., NuStar Energy L.P., the Lenders
party thereto and Mizuho Bank, Ltd., as Issuing
Bank and Administrative Agent
Sixth Amendment to Letter of Credit Agreement,
dated as of November 3, 2014, among NuStar
Logistics, L.P., NuStar Energy L.P., the Lenders
party thereto and Mizuho Bank, Ltd., as Issuing
Bank and Administrative Agent
Seventh Amendment to Letter of Credit Agreement,
dated as of April 30, 2015, among NuStar
Logistics, L.P., NuStar Energy L.P., the Lenders
party thereto and Mizuho Bank, Ltd., as Issuing
Bank and Administrative Agent
Eighth Amendment to Letter of Credit Agreement,
dated as of May 6, 2016, among NuStar Logistics,
L.P., NuStar Energy L.P., the Lenders party thereto
and Mizuho Bank, Ltd., as Issuing Bank and
Administrative Agent
NuStar Energy L.P.’s Annual Report on Form 10-K
for year ended December 31, 2014 (File No.
001-16417), Exhibit 10.11
NuStar Energy L.P.’s Annual Report on Form 10-K
for year ended December 31, 2014 (File No.
001-16417), Exhibit 10.12
NuStar Energy L.P.’s Annual Report on Form 10-K
for year ended December 31, 2014 (File No.
001-16417), Exhibit 10.13
NuStar Energy L.P.’s Current Report on Form 8-K
filed November 6, 2014 (File No. 001-16417),
Exhibit 10.1
NuStar Energy L.P.’s Quarterly Report on Form 10-
Q for quarter ended June 30, 2015 (File No.
001-16417), Exhibit 10.02
NuStar Energy L.P.’s Quarterly Report on Form 10-
Q for quarter ended June 30, 2016 (File No.
001-16417), Exhibit 10.01
Lease Agreement between Parish of St. James,
State of Louisiana and NuStar Logistics, L.P. dated
as of December 1, 2010
NuStar Energy L.P.’s Current Report on Form 8-K
filed December 30, 2010 (File No. 001-16417),
Exhibit 10.01
NuStar Energy L.P.’s Current Report on Form 8-K
filed September 9, 2014 (File No. 001-16417),
Exhibit 10.01
NuStar Energy L.P.’s Current Report on Form 8-K
filed November 6, 2014 (File No. 001-16417),
Exhibit 10.3
NuStar Energy L.P.’s Quarterly Report on Form 10-
Q for quarter ended September 30, 2015 (File No.
001-16417), Exhibit 10.01
NuStar Energy L.P.’s Quarterly Report on Form 10-
Q for quarter ended June 30, 2016 (File No.
001-16417), Exhibit 10.02
Letter of Credit Agreement dated as of September
3, 2014 among NuStar Logistics, L.P., NuStar
Energy L.P., the Lenders party thereto and The
Bank of Tokyo-Mitsubishi UFJ, Ltd., as Issuing
Bank and Administrative Agent
Amendment No. 1 to Letter of Credit Agreement
and Subsidiary Guaranty Agreement dated as of
November 3, 2014 among NuStar Logistics, L.P.,
NuStar Energy L.P., the Lenders party thereto and
The Bank of Tokyo-Mitsubishi UFJ, Ltd., as
Issuing Bank and Administrative Agent
Maturity Extension Letter (Amendment No. 2) to
Letter of Credit Agreement and Subsidiary
Guaranty Agreement dated as of August 19, 2015
among NuStar Logistics, L.P., NuStar Energy L.P.,
the Lenders party thereto and The Bank of Tokyo-
Mitsubishi UFJ, Ltd., as Issuing Bank and
Administrative Agent
Maturity Extension Letter (Amendment No. 3) to
Letter of Credit Agreement and Subsidiary
Guaranty Agreement dated as of July 15, 2016
among NuStar Logistics, L.P., NuStar Energy L.P.,
the Lenders party thereto and The Bank of Tokyo-
Mitsubishi UFJ, Ltd., as Issuing Bank and
Administrative Agent
167
Table of Contents
10.18
10.19
10.20
10.21
10.22
10.23
+10.24
+10.25
+10.26
+10.27
+10.28
+10.29
+10.30
Lease Agreement between Parish of St. James,
State of Louisiana and NuStar Logistics, L.P. dated
as of August 1, 2011
NuStar Energy L.P.’s Current Report on Form 8-K
filed August 10, 2011 (File No. 001-16417),
Exhibit 10.01
Letter of Credit Agreement dated as of June 5, 2013
among NuStar Logistics, L.P., NuStar Energy L.P.,
the Lenders party thereto and The Bank of Nova
Scotia, as Issuing Bank and Administrative Agent
Amendment No. 1 to Letter of Credit Agreement
and Subsidiary Guaranty Agreement dated as of
November 3, 2014 among NuStar Logistics, L.P.,
NuStar Energy L.P., the Lenders party thereto and
The Bank of Nova Scotia, as Issuing Bank and
Administrative Agent
Purchase and Sale Agreement, dated as of June 15,
2015, among NuStar Energy Services, Inc., NuStar
Logistics, L.P., NuStar Pipeline Operating
Partnership L.P. and NuStar Supply & Trading
LLC, as Originators, NuStar Energy L.P., as
Servicer, and NuStar Finance LLC, as Buyer
Receivables Financing Agreement, dated as of June
15, 2015, by and among NuStar Finance LLC, as
Borrower, the persons from time to time party
thereto as Lenders and Group Agents, PNC Bank,
National Association, as Administrative Agent, and
NuStar Energy L.P., as initial Servicer
Omnibus Amendment, dated as of January 15,
2016, which is the First Amendment to the
Purchase and Sale Agreement referenced above and
the First Amendment to the Receivables Financing
Agreement referenced above among the respective
parties thereto
NuStar Energy L.P.’s Current Report on Form 8-K
filed June 11, 2013 (File No. 001-16417), Exhibit
10.01
NuStar Energy L.P.’s Current Report on Form 8-K
filed November 6, 2014 (File No. 001-16417),
Exhibit 10.2
NuStar Energy L.P.'s Current Report on Form 8-K
filed June 19, 2015 (File No. 001-16417), Exhibit
10.1
NuStar Energy L.P.'s Current Report on Form 8-K
filed June 19, 2015 (File No. 001-16417), Exhibit
10.2
NuStar Energy L.P.’s Annual Report on Form 10-K
for year ended December 31, 2015 (File No.
001-16417), Exhibit 10.26
NuStar GP, LLC Amended and Restated 2003
Employee Unit Incentive Plan, amended and
restated as of April 1, 2007
NuStar Energy L.P.’s Quarterly Report on Form 10-
Q for quarter ended June 30, 2007 (File No.
001-16417), Exhibit 10.03
NuStar GP, LLC Fifth Amended and Restated 2000
Long-Term Incentive Plan, amended and restated as
of January 28, 2016
NuStar Energy L.P.’s Proxy Statement on Schedule
14A filed December 17, 2015 (File No.
001-16417), Appendix A
Form of 2011 and 2012 Restricted Unit Award
Agreement under the NuStar GP, LLC Third
Amended and Restated 2000 Long-Term Incentive
Plan
NuStar Energy L.P.’s Current Report on Form 8-K
filed January 31, 2012 (File No. 001-16417),
Exhibit 10.2
Form of 2013 Restricted Unit Award Agreement
under the NuStar GP, LLC Third Amended and
Restated 2000 Long-Term Incentive Plan
NuStar Energy L.P.’s Annual Report on Form 10-K
for year ended December 31, 2013 (File No.
001-16417), Exhibit 10.15
Form of Restricted Unit Award Agreement under
the NuStar GP, LLC Fifth Amended and Restated
2000 Long-Term Incentive Plan
*
Form of Performance Unit Agreement under the
NuStar GP, LLC Second Amended and Restated
2000 Long-Term Incentive Plan (substantially the
same for 2012 and 2013 awards with appropriate
adjustments based on award dates)
Form of 2013 Non-employee Director Restricted
Unit Agreement under the NuStar GP, LLC Third
Amended and Restated 2000 Long-Term Incentive
Plan
NuStar Energy L.P.’s Annual Report on Form 10-K
for year ended December 31, 2009 (File No.
001-16417), Exhibit 10.11
NuStar Energy L.P.’s Annual Report on Form 10-K
for year ended December 31, 2013 (File No.
001-16417), Exhibit 10.21
168
Table of Contents
+10.31
Form of Non-employee Director Restricted Unit
Award Agreement under the NuStar GP, LLC Fifth
Amended and Restated 2000 Long-Term Incentive
Plan
*
+10.32
NuStar Energy L.P. Annual Bonus Plan
+10.33
+10.34
Form of NuStar Energy L.P. Amended and Restated
Change of Control Severance Agreement
NuStar Excess Pension Plan, amended and restated
effective as of January 1, 2014
+10.35
NuStar Excess Thrift Plan, amended and restated
effective as of January 1, 2008
NuStar Energy L.P.’s Annual Report on Form 10-K
for year ended December 31, 2006 (File No.
001-16417), Exhibit 10.18
NuStar Energy L.P.’s Current Report on Form 8-K
filed August 4, 2016 (File No. 001-16417),
Exhibit 10.1
NuStar Energy L.P.’s Annual Report on Form 10-K
for year ended December 31, 2015 (File No.
001-16417), Exhibit 10.45
NuStar Energy L.P.’s Annual Report on Form 10-K
for year ended December 31, 2008 (File No.
001-16417), Exhibit 10.30
10.36
10.37
10.38
10.39
10.40
10.41
10.42
10.43
10.44
10.45
Non-Compete Agreement, dated July 19, 2006,
between Valero GP Holdings, LLC, Valero L.P.,
Riverwalk Logistics, L.P. and Valero GP, LLC
NuStar Energy L.P.’s Quarterly Report on Form 10-
Q for quarter ended September 30, 2006 (File No.
001-16417), Exhibit 10.03
Services Agreement, effective as of January 1,
2008, between NuStar GP, LLC and NuStar Energy
L.P.
NuStar Energy L.P.’s Quarterly Report on Form 10-
Q for quarter ended March 31, 2008 (File No.
001-16417), Exhibit 10.01
Amended and Restated Services Agreement dated
March 1, 2016 between NuStar Energy L.P., NuStar
GP Holdings, LLC, NuStar GP, LLC and NuStar
Services Company LLC
NuStar Energy L.P.’s Current Report on Form 8-K
filed March 1, 2016 (File No. 001-16417), Exhibit
10.2
Assignment and Assumption Agreement dated
March 1, 2016 between NuStar GP, LLC and
NuStar Services Company LLC
NuStar Energy L.P.’s Current Report on Form 8-K
filed March 1, 2016 (File No. 001-16417), Exhibit
10.1
Amended and Restated Aircraft Time Sharing
Agreement, dated as of September 4, 2009,
between NuStar Logistics, L.P. and William E.
Greehey
Purchase and Sale Agreement by and among
NuStar Energy L.P., NuStar Logistics, L.P., NuStar
Asphalt Refining, LLC, NuStar Marketing LLC,
NuStar GP, LLC, NuStar Asphalt LLC and Asphalt
Acquisition LLC dated as of July 3, 2012
Letter Agreement by and among Asphalt
Acquisition LLC, NuStar Energy L.P., NuStar
Logistics, L.P., NuStar Asphalt Refining, LLC,
NuStar Marketing LLC, NuStar GP, LLC and
NuStar Asphalt LLC dated August 2, 2012
Amendment No. 1 to Purchase and Sale Agreement
dated as of September 28, 2012 by and among
NuStar Energy L.P., NuStar Logistics, L.P., NuStar
Asphalt Refining, LLC, NuStar Marketing LLC,
NuStar GP, LLC, NuStar Asphalt LLC and Asphalt
Acquisition LLC
NuStar Energy L.P.’s Annual Report on Form 10-K
for year ended December 31, 2009 (File No.
001-16417), Exhibit 10.24
NuStar Energy L.P.’s Current Report on Form 8-K
filed July 6, 2012 (File No. 001-16417), Exhibit
10.01
NuStar Energy L.P.’s Quarterly Report on Form 10-
Q for quarter ended September 30, 2012 (File No.
001-16417), Exhibit 10.02
NuStar Energy L.P.’s Quarterly Report on Form 10-
Q for quarter ended September 30, 2012 (File No.
001-16417), Exhibit 10.03
Amended and Restated Transaction Agreement by
and between LG Asphalt L.P. and NuStar Logistics,
L.P. dated as of December 20, 2013
NuStar Energy L.P.’s Annual Report on Form 10-K
for year ended December 31, 2013 (File No.
001-16417), Exhibit 10.47
Amendment No. 1 to Amended and Restated
Transaction Agreement dated as of January 29,
2014
NuStar Energy L.P.’s Annual Report on Form 10-K
for year ended December 31, 2013 (File No.
001-16417), Exhibit 10.48
169
Amendment No. 2 to Amended and Restated
Transaction Agreement dated as of February 26,
2014
NuStar Energy L.P.’s Annual Report on Form 10-K
for year ended December 31, 2013 (File No.
001-16417), Exhibit 10.49
Table of Contents
10.46
12.01
21.01
23.01
24.01
31.01
31.02
32.01
32.02
Statement of Computation of Ratio of Earnings to
Fixed Charges
List of subsidiaries of NuStar Energy L.P.
Consent of KPMG LLP dated February 23, 2017
(NuStar Energy L.P.)
Powers of Attorney (included in signature page of
this Form 10-K)
Rule 13a-14(a) Certification (under Section 302 of
the Sarbanes-Oxley Act of 2002) of principal
executive officer
Rule 13a-14(a) Certification (under Section 302 of
the Sarbanes-Oxley Act of 2002) of principal
financial officer
Section 1350 Certification (under Section 906 of
the Sarbanes-Oxley Act of 2002) of principal
executive officer
Section 1350 Certification (under Section 906 of
the Sarbanes-Oxley Act of 2002) of principal
financial officer
101.INS
XBRL Instance Document
101.SCH
XBRL Taxonomy Extension Schema Document
101.CAL
101.DEF
101.LAB
101.PRE
XBRL Taxonomy Extension Calculation Linkbase
Document
XBRL Taxonomy Extension Definition Linkbase
Document
XBRL Taxonomy Extension Label Linkbase
Document
XBRL Taxonomy Extension Presentation Linkbase
Document
*
*
*
*
*
*
**
**
*
*
*
*
*
*
*
**
+
Filed herewith.
Furnished herewith.
Identifies management contracts or compensatory plans or arrangements required to be filed as an exhibit hereto
pursuant to Item 15(c) of Form 10-K.
Copies of exhibits filed as a part of this Form 10-K may be obtained by unitholders of record at a charge of $0.15 per page,
minimum $5.00 each request. Direct inquiries to Corporate Secretary, NuStar Energy L.P., 19003 IH-10 West, San Antonio,
Texas 78257.
ITEM 16. FORM 10-K SUMMARY
Not applicable.
170
Table of Contents
Pursuant to the requirements of Section 13 or 15(d) of the Exchange Act, the registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.
SIGNATURES
NUSTAR ENERGY L.P.
(Registrant)
By:
By:
By:
By:
Riverwalk Logistics, L.P., its general partner
By: NuStar GP, LLC, its general partner
/s/ Bradley C. Barron
Bradley C. Barron
President and Chief Executive Officer
February 23, 2017
/s/ Thomas R. Shoaf
Thomas R. Shoaf
Executive Vice President and Chief Financial Officer
February 23, 2017
/s/ Jorge A. del Alamo
Jorge A. del Alamo
Senior Vice President and Controller
February 23, 2017
171
Table of Contents
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below hereby constitutes and appoints
Bradley C. Barron, Thomas R. Shoaf and Amy L. Perry, or any of them, each with power to act without the other, his true and
lawful attorney-in-fact and agent, with full power of substitution and resubstitution, for him and in his name, place and stead, in
any and all capacities, to sign any or all subsequent amendments and supplements to this Annual Report on Form 10-K, and to
file the same, or cause to be filed the same, with all exhibits thereto, and other documents in connection therewith, with the
Securities and Exchange Commission, granting unto each said attorney-in-fact and agent full power to do and perform each and
every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as he might
or could do in person, hereby qualifying and confirming all that said attorney-in-fact and agent or his substitute or substitutes
may lawfully do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following
persons on behalf of the registrant and in the capacities and on the dates indicated.
Signature
Title
Date
/s/ William E. Greehey
William E. Greehey
/s/ Bradley C. Barron
Bradley C. Barron
/s/ Thomas R. Shoaf
Thomas R. Shoaf
/s/ Jorge A. del Alamo
Jorge A. del Alamo
/s/ J. Dan Bates
J. Dan Bates
/s/ Dan J. Hill
Dan J. Hill
/s/ Robert J. Munch
Robert J. Munch
/s/ W. Grady Rosier
W. Grady Rosier
Chairman of the Board
February 23, 2017
President, Chief Executive
Officer and Director
(Principal Executive Officer)
Executive Vice President
and Chief Financial Officer
(Principal Financial Officer)
February 23, 2017
February 23, 2017
Senior Vice President and Controller
(Principal Accounting Officer)
February 23, 2017
Director
February 23, 2017
Director
February 23, 2017
Director
February 23, 2017
Director
February 23, 2017
172